(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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

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.~~Commission (the “SEC”). In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk” and “Part II, Item 1A. Risk Factors” in this Report and “Part I, Item 1. Business — Competition, Markets and Regulations,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

(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.


	March 31, 2011			December 31, 2010			June 30, 2011			December 31, 2010
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	520,651		$	111,160		$	352,421		$	111,160
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,171 and $1,155 as of March 31, 2011 and December 31, 2010, respectively		276,338			237,511
Trade, net of allowance for doubtful accounts of $1,056 and $1,155 as of June 30, 2011 and December 31, 2010, respectively								266,476			237,511
Due from affiliates		955			7,792			2,702			7,792
Income taxes receivable		30,900			30,901			3,674			30,901
Inventories		187,715			173,615			234,108			173,615
Prepaid expenses		10,010			11,441			21,342			11,441
Deferred income taxes		22,802			156,650			163			156,650
Discontinued operations held for sale		—			281,741			—			281,741
Other current assets:
Derivatives		147,643			171,679			154,129			171,679
Other		38,579			14,693			36,092			14,693

Total current assets		1,235,593			1,197,183			1,071,107			1,197,183

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		11,069,563			10,739,114			11,541,101			10,739,114
Unproved properties		200,209			191,112			213,230			191,112
Accumulated depletion, depreciation and amortization		(3,495,838	)		(3,366,440	)		(3,637,605	)		(3,366,440	)

Total property, plant and equipment		7,773,934			7,563,786			8,116,726			7,563,786

Deferred income taxes								1,878			—
Goodwill		298,145			298,182			298,177			298,182
Other property and equipment, net		380,376			283,542			431,214			283,542
Other assets:
Investment in unconsolidated affiliate		109,391			72,045			155,701			72,045
Derivatives		106,210			151,011			142,361			151,011
Other, net of allowance for doubtful accounts of $2,364 and $2,519 as of March 31, 2011 and December 31, 2010, respectively		122,337			113,353
Other, net of allowance for doubtful accounts of $358 and $2,519 as of June 30, 2011 and December 31, 2010, respectively								135,924			113,353

	$	10,025,986		$	9,679,102		$	10,353,088		$	9,679,102

The financial information included as of ~~March 31,~~June 30, 2011 has been prepared by management

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


	March 31, 2011			December 31, 2010			June 30, 2011			December 31, 2010
	(Unaudited)						(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	350,030		$	354,890		$	490,434		$	354,890
Due to affiliates		19,303			64,260			26,962			64,260
Interest payable		33,942			59,008			57,366			59,008
Income taxes payable		33,072			19,168			5,927			19,168
Deferred income taxes		—			1,144			19,588			1,144
Discontinued operations held for sale		—			108,592			—			108,592
Other current liabilities:
Derivatives		173,628			80,997			76,008			80,997
Deferred revenue		44,327			44,951			43,580			44,951
Other		41,562			36,210			35,776			36,210

Total current liabilities		695,864			769,220			755,641			769,220

Long-term debt		2,562,688			2,601,670			2,570,978			2,601,670
Derivatives		179,914			56,574			108,075			56,574
Deferred income taxes		1,763,976			1,751,310			1,844,503			1,751,310
Deferred revenue		31,610			42,069			21,150			42,069
Other liabilities		238,367			232,234			236,777			232,234
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 127,469,647 and 126,212,256 shares issued at March 31, 2011 and December 31, 2010, respectively		1,275			1,262
Common stock, $.01 par value; 500,000,000 shares authorized; 127,554,683 and 126,212,256 shares issued at June 30, 2011 and December 31, 2010, respectively								1,276			1,262
Additional paid-in capital		3,060,249			3,022,768			3,070,827			3,022,768
Treasury stock, at cost: 11,276,450 and 10,903,743 at March 31, 2011 and December 31, 2010, respectively		(456,359	)		(421,235	)
Treasury stock, at cost: 11,311,097 and 10,903,743 at June 30, 2011 and December 31, 2010, respectively								(459,657	)		(421,235	)
Retained earnings		1,854,041			1,510,427			2,099,623			1,510,427
Accumulated other comprehensive income–deferred hedge gains, net of tax		3,439			7,361
Accumulated other comprehensive income - net deferred hedge gains, net of tax								2,863			7,361

Total stockholders’ equity attributable to common stockholders		4,462,645			4,120,583			4,714,932			4,120,583
Noncontrolling interests in consolidating subsidiaries		90,922			105,442			101,032			105,442

Total stockholders’ equity		4,553,567			4,226,025			4,815,964			4,226,025
Commitments and contingencies

	$	10,025,986		$	9,679,102		$	10,353,088		$	9,679,102

The financial information included as of ~~March 31,~~June 30, 2011 has been prepared by management

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


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Revenues and other income:
Oil and gas	$	497,130		$	472,045		$	583,931		$	422,042		$	1,081,061		$	894,087
Interest and other		32,687			18,008			18,454			16,952			51,141			34,960
Gain (loss) on disposition of assets, net		(2,191	)		16,943			(296	)		7,645			(2,487	)		24,588

		527,626			506,996			602,089			446,639			1,129,715			953,635

Costs and expenses:
Oil and gas production		99,931			86,100			102,455			94,012			202,386			180,112
Production and ad valorem taxes		33,296			27,061			35,864			25,338			69,160			52,399
Depletion, depreciation and amortization		140,373			144,428			153,898			144,309			294,271			288,737
Exploration and abandonments		17,643			16,848			19,914			22,743			37,557			39,591
General and administrative		44,106			38,315			44,644			40,433			88,750			78,748
Accretion of discount on asset retirement obligations		2,655			2,859			2,658			2,529			5,313			5,388
Interest		45,227			47,523			45,768			45,368			90,995			92,891
Hurricane activity, net		71			(7,410	)		(2	)		5,184			69			(2,226	)
Derivative (gains) losses, net		244,432			(265,476	)		(229,478	)		(177,528	)		14,954			(443,004	)
Other		17,881			15,946			14,388			14,193			32,269			30,139

		645,615			106,194			190,109			216,581			835,724			322,775

Income (loss) from continuing operations before income taxes		(117,989	)		400,802
Income tax benefit (provision)		47,151			(144,007	)
Income from continuing operations before income taxes								411,980			230,058			293,991			630,860
Income tax provision								(144,696	)		(83,220	)		(97,545	)		(227,227	)

Income (loss) from continuing operations		(70,838	)		256,795
Income from discontinued operations, net of tax		414,642			3,811
Income from continuing operations								267,284			146,838			196,446			403,633
Income (loss) from discontinued operations, net of tax								(1,584	)		41,851			413,058			45,662

Net income		343,804			260,606			265,700			188,689			609,504			449,295
Net (income) loss attributable to the noncontrolling interests		4,790			(15,352	)
Net income attributable to the noncontrolling interests								(20,123	)		(21,113	)		(15,333	)		(36,465	)

Net income attributable to common stockholders	$	348,594		$	245,254		$	245,577		$	167,576		$	594,171		$	412,830

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.57	)	$	2.06
Income from discontinued operations attributable to common stockholders		3.53			0.03
Income from continuing operations attributable to common stockholders							$	2.08		$	1.07		$	1.53		$	3.12
Income (loss) from discontinued operations attributable to common stockholders								(0.01	)		0.35			3.50			0.39

Net income attributable to common stockholders	$	2.96		$	2.09		$	2.07		$	1.42		$	5.03		$	3.51

Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.57	)	$	2.05
Income from discontinued operations attributable to common stockholders		3.53			0.03
Income from continuing operations attributable to common stockholders							$	2.04		$	1.06		$	1.50		$	3.10
Income (loss) from discontinued operations attributable to common stockholders								(0.01	)		0.35			3.40			0.39

Net income attributable to common stockholders	$	2.96		$	2.08		$	2.03		$	1.41		$	4.90		$	3.49

Weighted average shares outstanding:
Basic		115,869			114,655			116,213			115,104			116,042			114,880

Diluted		115,869			115,462			118,592			116,006			118,986			115,735

Dividends declared per share	$	0.04		$	0.04		$	—		$	—		$	0.04		$	0.04

Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	(66,048	)	$	241,443
Income from discontinued operations, net of tax		414,642			3,811
Income from continuing operations							$	247,161		$	125,725		$	181,113		$	367,168
Income (loss) from discontinued operations, net of tax								(1,584	)		41,851			413,058			45,662

Net income	$	348,594		$	245,254		$	245,577		$	167,576		$	594,171		$	412,830

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


				Stockholders’ Equity Attributable To Common Stockholders																							Stockholders’ Equity Attributable To Common Stockholders
	Shares Outstanding			Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interests			Total Stockholders’ Equity			Shares Outstanding			Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interests			Total Stockholders’ Equity
Balance as of December 31, 2010		115,309		$	1,262	$	3,022,768		$	(421,235	)	$	1,510,427		$	7,361		$	105,442		$	4,226,025			115,309		$	1,262	$	3,022,768		$	(421,235	)	$	1,510,427		$	7,361		$	105,442		$	4,226,025
Dividends declared ($0.04 per share)		—			—		—			—			(4,759	)		—			—			(4,759	)		—			—		—			—			(4,739	)		—			—			(4,739	)
Exercise of long-term incentive plan stock options		14			—		—			558			(221	)		—			—			337			16			—		—			598			(236	)		—			—			362
Treasury stock purchases		(387	)		—		—			(35,682	)		—			—			—			(35,682	)		(424	)		—		—			(39,020	)		—			—			(198	)		(39,218	)
Tax benefit related to stock-based compensation		—			—		28,083			—			—			—			—			28,083			—			—		27,937			—			—			—			—			27,937
Disposition of subsidiary		—			—		(508	)		—			—			—			—			(508	)		—			—		(508	)		—			—			—			—			(508	)
Compensation costs:
Vested compensation awards, net		1,257			13		(13	)		—			—			—			—			—			1,343			14		(14	)		—			—			—			—			—
Compensation costs included in net income		—			—		9,919			—			—			—			320			10,239			—			—		20,644			—			—			—			632			21,276
Cash distributions to noncontrolling interests		—			—		—			—			—			—			(6,664	)		(6,664	)		—			—		—			—			—			—			(13,366	)		(13,366	)
Net income (loss)		—			—		—			—			348,594			—			(4,790	)		343,804
Other comprehensive loss:
Net income																									—			—		—			—			594,171			—			15,333			609,504
Other comprehensive activity:
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations		—			—		—			—			—			(3,922	)		(3,386	)		(7,308	)		—			—		—			—			—			(4,498	)		(6,811	)		(11,309	)

Balance as of March 31, 2011		116,193		$	1,275	$	3,060,249		$	(456,359	)	$	1,854,041		$	3,439		$	90,922		$	4,553,567
Balance as of June 30, 2011																									116,244		$	1,276	$	3,070,827		$	(459,657	)	$	2,099,623		$	2,863		$	101,032		$	4,815,964

The financial information included herein has been prepared by management without audit by independent registered public accountants.

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


	Three Months Ended March 31,						Six Months Ended June 30,
	2011			2010			2011			2010
Cash flows from operating activities:
Net income	$	343,804		$	260,606		$	609,504		$	449,295
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		140,373			144,428			294,271			288,737
Exploration expenses, including dry holes		1,481			3,587			4,275			7,973
Hurricane activity, net								—			3,500
Deferred income taxes		(55,868	)		141,545			75,507			220,352
(Gain) loss on disposition of assets, net		2,191			(16,943	)		2,487			(24,588	)
Accretion of discount on asset retirement obligations		2,655			2,859			5,313			5,388
Discontinued operations		(408,065	)		21,558			(407,115	)		41,463
Interest expense		7,637			7,408			15,432			14,920
Derivative related activity		276,683			(281,871	)		56,380			(442,087	)
Amortization of stock-based compensation		10,174			9,624			21,155			19,049
Amortization of deferred revenue		(11,083	)		(22,483	)		(22,290	)		(45,070	)
Other noncash items		(20,488	)		(403	)		(18,277	)		1,324
Change in operating assets and liabilities
Accounts receivable, net		(25,270	)		48,080			(23,605	)		96,376
Income taxes receivable		1			21,264			27,226			23,440
Inventories		(29,319	)		17,429			(74,136	)		12,479
Prepaid expenses		1,342			435			(9,990	)		(10,204	)
Other current assets		3,305			1,226			8,772			(7,192	)
Accounts payable		(89,980	)		(34,296	)		6,201			50,458
Interest payable		(25,066	)		(13,314	)		(1,642	)		7,014
Income taxes payable		15,354			(1,536	)		(11,485	)		(4,470	)
Other current liabilities		3,353			(9,840	)		6,471			(14,943	)

Net cash provided by operating activities		143,214			299,363			564,454			693,214

Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold		810,470			34,985			813,520			297,312
Investment in unconsolidated subsidiary		(37,048	)		—			(82,857	)		(108	)
Additions to oil and gas properties		(309,974	)		(156,529	)		(757,148	)		(461,502	)
Additions to other assets and other property and equipment, net		(129,280	)		(44,999	)		(215,367	)		(74,075	)

Net cash provided by (used in) investing activities		334,168			(166,543	)
Net cash used in investing activities								(241,852	)		(238,373	)

Cash flows from financing activities:
Borrowings under long-term debt		60,610			87,154			72,610			182,997
Principal payments on long-term debt		(105,810	)		(206,264	)		(115,810	)		(424,107	)
Contributions from noncontrolling interests		—			1,151			—			1,151
Distributions to noncontrolling interests		(6,664	)		(6,605	)		(13,366	)		(13,451	)
Borrowings (payments) of other liabilities		(20	)		2,818
Payments of other liabilities								(305	)		(20,325	)
Exercise of long-term incentive plan stock options		337			2,583			362			3,452
Purchases of treasury stock		(35,682	)		(12,978	)		(39,218	)		(13,402	)
Excess tax benefits from share-based payment arrangements		28,083			6,705			27,937			4,090
Payment of financing fees		(8,672	)		(147	)		(8,739	)		(145	)
Dividends paid		(73	)		(65	)		(4,812	)		(4,783	)

Net cash used in financing activities		(67,891	)		(125,648	)		(81,341	)		(284,523	)

Net increase in cash and cash equivalents		409,491			7,172			241,261			170,318
Cash and cash equivalents, beginning of period		111,160			27,368			111,160			27,368

Cash and cash equivalents, end of period	$	520,651		$	34,540		$	352,421		$	197,686

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


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Net income	$	343,804		$	260,606		$	265,700		$	188,689		$	609,504		$	449,295

Other comprehensive loss:
Other comprehensive activity:
Net hedge gains included in continuing operations		(8,056	)		(20,926	)		(8,139	)		(20,697	)		(16,195	)		(41,623	)
Income tax provision		748			5,035			4,138			6,037			4,886			11,072

Other comprehensive loss		(7,308	)		(15,891	)
Other comprehensive activity								(4,001	)		(14,660	)		(11,309	)		(30,551	)

Comprehensive income		336,496			244,715			261,699			174,029			598,195			418,744

Comprehensive (income) loss attributable to the noncontrolling interests		8,176			(11,036	)
Comprehensive income attributable to the noncontrolling interests								(16,698	)		(16,740	)		(8,522	)		(27,758	)

Comprehensive income attributable to common stockholders	$	344,672		$	233,679		$	245,001		$	157,289		$	589,673		$	390,986

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

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.

Presentation.In the opinion of management, the consolidated financial statements of the Company as of ~~March 31,~~June 30, 2011 and for the three and six months ended ~~March 31,~~June 30, 2011 and 2010 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). These consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

Discontinued operations.During December 2010, the Company committed to a plan to divest 100 percent of the Company’s share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as “Pioneer Tunisia”). In February 2011, the Company completed the sale of Pioneer Tunisia to an unaffiliated third party. Accordingly, the Company classified the assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying balance sheet as of December 31, 2010 and has classified the results of operations of Pioneer Tunisia as discontinued operations, net of tax for the three and six months ended ~~March 31,~~June 30, 2011 and 2010 in the accompanying consolidated statements of operations (representing a recasting of the Pioneer Tunisia results of operations for the three and six months ended ~~March 31,~~June 30, 2010, which were originally classified as continuing operations). See Note Q for more information regarding the sale of Pioneer Tunisia.

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

Allowances for doubtful accounts. As of ~~March 31,~~June 30, 2011 and December 31, 2010, the Company’s allowances for doubtful accounts totaled ~~$3.5~~$1.4 million and $3.7 million, respectively. Changes in the Company’s allowance for doubtful accounts during the three and six months ended ~~March 31,~~June 30, 2011 are summarized in the following table:


	Three Months Ended March 31, 2011
	(in thousands)			Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
				(in thousands)
Beginning allowance for doubtful accounts balance	$	3,674		$	3,535		$	3,674
Amount recorded in other expense for bad debt expense		18
Amount recorded in other expense for bad debt recoveries					(1,815	)		(1,797	)
Other net decreases		(157	)		(306	)		(463	)


Ending allowance for doubtful accounts balance	$	3,535		$	1,414		$	1,414

Inventories.Inventories used in continuing operations consisted of ~~$206.8~~$247.9 million and $183.4 million of materials and supplies and ~~$3.8~~$4.1 million and $3.9 million of commodities as of ~~March 31,~~June 30, 2011 and December 31, 2010, respectively. As of ~~March 31,~~June 30, 2011 and December 31, 2010, the Company’s materials and supplies inventory was net of ~~$3.8~~$2.5 million and $3.6 million, respectively, of valuation reserve allowances. As of ~~March 31,~~June 30, 2011 and December 31, 2010, the Company estimated that ~~$22.9~~$17.9 million and $13.7 million, respectively, of its materials and supplies inventory would not be utilized or sold within one year. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets. As of December 31, 2010, the Company also had inventory in Tunisia totaling $13.6 million that is classified as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2010.

Derivatives and hedging.All derivatives are recorded onin the accompanying consolidated balance sheets at estimated fair value. See Note D for further information regarding the fair value of the Company’s derivatives. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. Changes in the fair value of effective cash

flow hedges prior to the Company’s discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income – net deferred hedge gains, net of tax (“AOCI – Hedging”), in the stockholders’ equity section of the accompanying consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are recognized in the Company’s earnings. Since February 1, 2009, the Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and ~~master netting~~ counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company’s and Pioneer Southwest Energy Partners L.P.’s (“Pioneer Southwest,” a majority-owned and consolidated subsidiary) credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. Pioneer Southwest’s credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate (“LIBOR”) curves plus 250 basis points, representing Pioneer Southwest’s estimated borrowing rate.

Goodwill. Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2010, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

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

The Company also owns a majority interest in Sendero Drilling Company, LLC (“Sendero”), which owns and operates land-based drilling rigs in the United States. ~~As of March 31, 2011, Sendero owned 14 drilling rigs operating, or being readied to operate, under contracts to the Company in the Spraberry field.~~ 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 ~~$90.9~~$101.0 million and $105.4 million as of ~~March 31,~~June 30, 2011 and December 31, 2010, respectively. The Company recorded a net ~~loss~~income attributable to the noncontrolling interests of ~~$4.8~~$20.1 million and $15.3 million for the three and six months ended ~~March 31,~~June 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of ~~$15.4~~$21.1 million and $36.5 million for the three and six months ended March 31, 2010. The net loss attributable to noncontrolling interests for the first quarter of 2011 was primarily due to noncash mark-to-market derivative losses recorded by Pioneer Southwest during the three months ended March 31, 2011.June 30, 2010, respectively.

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

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

Stock-based compensation. For stock-based compensation equity awards granted or modified, compensation expense is being recognized in the Company’s financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The amount of compensation expense recognized at any date is

at least equal to the portion of the ~~grant-date~~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, orrestricted stock units, partnership unit awards ~~and~~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 ~~March 31,~~June 30, 2011, accounts payable – due to affiliates includes ~~$1.6~~$3.9 million of liabilities attributable to the Liability Awards.

For the three and six months ended ~~March 31,~~June 30, 2011, the Company recorded ~~$13.0~~$13.8 million and $26.4 million, respectively, of stock-based compensation costs for all plans, as compared to ~~$9.8~~$10.5 million and $20.6 million for the same ~~period~~respective periods of 2010. As of ~~March 31,~~June 30, 2011, there was ~~$109.1~~$93.1 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including ~~$28.0~~$21.6 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which on a weighted average basis is a period of less than three years.

The Company’s issued shares, as reflected in the consolidated balance sheets at ~~March 31,~~June 30, 2011 and December 31, 2010, do not include ~~566,389~~536,775 and 825,796 common shares, respectively, associated with unvested stock-based compensation awards that have voting rights.

The following table summarizes the activity that occurred during the ~~three~~six months ended ~~March 31,~~June 30, 2011, for each type of share-based incentive award issued by Pioneer:


	Restricted Stock Equity Awards			Restricted Stock Liability Awards			Performance Units		Stock Options			Pioneer Southwest LTIP Restricted Units		Pioneer Southwest LTIP Phantom Units
																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		2,559,779			215,134			263,729			507,539			12,212			35,118
Awards granted		404,002			182,982			43,495		86,903			—		30,039		427,384			182,982			43,495			86,903			6,812			30,039
Awards vested		(954,070	)		(63,232	)		—		—			—		—		(1,015,713	)		(63,556	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—		(14,290	)		—		—		—			—			—			(15,290	)		—			—
Awards forfeited		(16,011	)		(4,718	)		—		—			—		—		(37,914	)		(11,931	)		—			—			—			—

Outstanding at March 31, 2011		1,993,700			330,166			307,224		580,152			12,212		65,157
Outstanding at June 30, 2011																	1,933,536			322,629			292,417			579,152			7,492			65,157

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

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

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

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 ~~impaired.~~sold. The Company’s capitalized exploratory well and project costs are presented in proved properties in the consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The following table reflects the Company’s capitalized exploratory well and project activity during the three and six months ended ~~March 31,~~June 30, 2011:


	Three Months Ended March 31, 2011
	(in thousands)			Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
				(in thousands)
Beginning capitalized exploratory costs	$	96,193		$	80,530		$	96,193
Additions to exploratory costs pending the determination of proved reserves		74,264			140,081			214,345
Reclassification due to determination of proved reserves		(60,344	)		(135,338	)		(195,682	)
Disposition of assets sold		(28,938	)		—			(28,938	)
Exploratory well costs charged to exploration expense		(645	)		(162	)		(807	)


Ending capitalized exploratory costs	$	80,530		$	85,111		$	85,111

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


	March 31, 2011		December 31, 2010		June 30, 2011		December 31, 2010
	(in thousands, except project counts)				(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	80,530	$	70,635	$	77,129	$	70,635
More than one year		—		25,558		7,982		25,558

					$	85,111	$	96,193
	$	80,530	$	96,193


Number of projects with exploratory costs that have been suspended for a period greater than one year		—		3		1		3

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

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

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:

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 ~~March 31,~~June 30, 2011, for each of the fair value hierarchy levels:


	Fair Value Measurements at Reporting Date Using								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 March 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2011
	(in thousands)								(in thousands)

Assets:
Trading securities	$	319	$	25,118	$	—	$	25,437	$	289	$	30,149	$	—	$	30,438
Commodity derivatives		—		241,894		—		241,894		—		271,544		—		271,544
Interest rate derivatives		—		11,959		—		11,959
Interest rate derivatives (a)										—		24,946		—		24,946
Deferred compensation plan assets		39,582		—		—		39,582		40,223		—		—		40,223

Total assets	$	39,901	$	278,971	$	—	$	318,872	$	40,512	$	326,639	$	—	$	367,151


Liabilities:
Commodity derivatives	$	—	$	335,279	$	16,675	$	351,954	$	—	$	170,732	$	13,351	$	184,083
Interest rate derivatives		—		1,588		—		1,588
Pioneer Southwest credit facility		—		81,289		—		81,289		—		84,542		—		84,542
5.875% senior notes due 2016		482,663		—		—		482,663		482,139		—		—		482,139
6.65% senior notes due 2017		523,908		—		—		523,908		529,972		—		—		529,972
6.875% senior notes due 2018		481,415		—		—		481,415		496,698		—		—		496,698
7.50% senior notes due 2020		507,374		—		—		507,374		512,158		—		—		512,158
7.20% senior notes due 2028		250,000		—		—		250,000		250,000		—		—		250,000
2.875% senior convertible notes due 2038 (a)		854,400		—		—		854,400
2.875% senior convertible notes due 2038 (b)										742,800		—		—		742,800

Total liabilities	$	3,099,760	$	418,156	$	16,675	$	3,534,591	$	3,013,767	$	255,274	$	13,351	$	3,282,392

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


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months Ended March 31, 2011			Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)			(in thousands)
Beginning liability balance	$	(9,556	)	$	(16,675	)	$	(9,556	)
Total gains and losses:
Net unrealized losses included in earnings (a)		(7,118	)
Net unrealized gains (losses) included in earnings (a)					3,324			(3,795	)
Net realized losses included in earnings (a)		(2,696	)		(4,629	)		(7,325	)
Settlement payments		2,695			4,629			7,325

Ending liability balance	$	(16,675	)	$	(13,351	)	$	(13,351	)

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


	March 31, 2011				December 31, 2010				June 30, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)								(in thousands)

Assets:
Commodity price derivatives	$	241,894	$	241,894	$	304,434	$	304,434	$	271,544	$	271,544	$	304,434	$	304,434
Interest rate derivatives	$	11,959	$	11,959	$	18,256	$	18,256
Interest rate derivatives (a)									$	24,946	$	24,946	$	18,256	$	18,256
Trading securities	$	25,437	$	25,437	$	467	$	467	$	30,438	$	30,438	$	467	$	467
Deferred compensation plan assets	$	39,582	$	39,582	$	36,162	$	36,162	$	40,223	$	40,223	$	36,162	$	36,162

Liabilities:
Commodity price derivatives	$	351,954	$	351,954	$	136,867	$	136,867	$	184,083	$	184,083	$	136,867	$	136,867
Interest rate derivatives	$	1,588	$	1,588	$	704	$	704	$	—	$	—	$	704	$	704
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	85,000	$	81,289	$	81,200	$	77,241	$	87,000	$	84,542	$	81,200	$	77,241
5.875 % senior notes due 2016	$	398,936	$	482,663	$	396,880	$	475,194	$	401,037	$	482,139	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,079	$	523,908	$	484,045	$	516,632	$	484,114	$	529,972	$	484,046	$	516,632
6.875 % senior notes due 2018	$	449,200	$	481,415	$	449,192	$	480,969	$	449,209	$	496,698	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,502	$	507,374	$	446,433	$	494,145	$	446,572	$	512,158	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,926	$	250,000	$	249,925	$	259,350	$	249,927	$	250,000	$	249,925	$	259,350
2.875% senior convertible notes due 2038 ~~(a)~~(b)	$	449,045	$	854,400	$	444,994	$	728,400	$	453,119	$	742,800	$	444,994	$	728,400

Trading securities and deferred compensation plan assets. The Company’s trading securities represent securities that are both actively traded and not actively traded on major exchanges. The Company’s deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges plus unallocated contributions as of the measurement date. As of ~~March 31,~~June 30, 2011, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs except inputs for certain trading securities that are not actively traded on major exchanges, which were ~~provided by~~corroborated broker quotes representing Level 2 inputs.

Interest rate derivatives. The Company’s interest rate derivative assets and liabilities as of ~~March 31,~~June 30, 2011 represent swap contracts for $470 million notional amount of debt, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. The net derivative values attributable to the Company’s

interest rate derivative contracts as of ~~March 31,~~June 30, 2011 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company’s commodity derivatives represent oil, NGL, gas and ~~gas~~diesel swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company’s oil, gas and ~~gas~~diesel swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority and NGL derivative contract asset and liability measurements represent Level 3 inputs in the hierarchy priority.

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

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

Gas derivatives.The Company’s gas derivatives are swap, collar and three-way collar contracts for notional volumes of gas (expressed in millions of British thermal units “MMBtus”) contracted at various posted price indexes, including NYMEX Henry Hub (“HH”) ~~swap~~ 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.

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

(“NOLs”) and other deferred tax attributes in the U.S., state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of ~~March 31,~~June 30, 2011 and December 31, 2010, the Company’s valuation allowances were $9.9 million and $6.6 million, ~~and $33.1 million,~~ respectively. ~~The valuation allowance as~~As of December 31, 2010, ~~includes~~the Company also had a $26.5 million valuation allowance related to Tunisia operations, ~~that~~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 ~~March 31,~~June 30, 2011, the Company had no significant unrecognized tax benefits. The Company’s policy is to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2005. As of ~~March 31,~~June 30, 2011, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company’s liquidity, future results of operations or financial position.

Income tax (provisions) benefits.The Company’s income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010
	(in thousands)						(in thousands)

Current:
U.S. federal	$	—		$	(1,101	)	$	—		$	(2,199	)	$	—		$	(3,301	)
U.S. state		(2,398	)		(1,324	)		(2,538	)		(1,800	)		(4,936	)		(3,124	)
Foreign		(6,319	)		(37	)		(10,782	)		(413	)		(17,102	)		(450	)

		(8,717	)		(2,462	)		(13,320	)		(4,412	)		(22,038	)		(6,875	)


Deferred:
U.S. federal		40,787			(131,128	)		(140,948	)		(71,929	)		(100,160	)		(203,056	)
U.S. state		10,425			(9,460	)		304			(7,040	)		10,729			(16,500	)
Foreign		4,656			(957	)		9,268			161			13,924			(796	)

		55,868			(141,545	)		(131,376	)		(78,808	)		(75,507	)		(220,352	)

Income tax (provision) benefit	$	47,151		$	(144,007	)
Income tax provision							$	(144,696	)	$	(83,220	)	$	(97,545	)	$	(227,227	)

Discontinued operations.The Company’s income tax (provisions) benefits attributable to income from discontinued operations consisted of the following for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010
	(in thousands)						(in thousands)

Current:
U.S. state	$	(5,725	)	$	—		$	1,790		$	—		$	(3,935	)	$	—
Foreign		(1,849	)		444			(3,753	)		(5,737	)		(5,602	)		(5,294	)

		(7,574	)		444			(1,963	)		(5,737	)		(9,537	)		(5,294	)


Deferred:
U.S. federal		(227,321	)		70			4,832			(12,909	)		(222,490	)		(12,839	)
U.S. state		(2,148	)		—			80			—			(2,068	)		—
Foreign		(12,323	)		(16,981	)		4,669			(5,979	)		(7,653	)		(22,960	)

		(241,792	)		(16,911	)		9,581			(18,888	)		(232,211	)		(35,799	)

Income tax provision	$	(249,366	)	$	(16,467	)
Income tax (provision) benefit							$	7,618		$	(24,625	)	$	(241,748	)	$	(41,093	)

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 ~~March 31,~~June 30, 2011, the Company had no outstanding borrowings under the Credit Facility and $65.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.2 billion of unused borrowing capacity under the Credit Facility.

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds

transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin (“ABR Margin”), which is currently one percent based on the Company’s debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the “Applicable Margin”), which is currently two percent and is also determined by the Company’s debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the “ASK” rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company’s debt rating (currently 0.375 percent).

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

As of ~~March 31,~~June 30, 2011, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

In accordance with GAAP, the Company accounted for the entry into the Credit Facility as an extinguishment of the Expired Credit Facility. Associated therewith, the Company recorded a $2.4 million loss on extinguishment of debt to write off the unamortized issuance costs of the Company’s ~~expired credit facility,~~Expired Credit Facility, which is included in other expense in the accompanying consolidated statement of operations for the ~~three~~six months ended ~~March 31,~~June 30, 2011 (see Note P).

Convertible senior notes. As of ~~March 31,~~June 30, 2011 and December 31, 2010, the Company had $480 million of 2.875% Convertible Senior Notes outstanding. The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company’s common stock pursuant to a formula.

~~Effective April 1,~~The Company’s stock price during March 2011 caused the Company’s 2.875% Convertible Senior Notes ~~became~~to become convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During July and August 2011, the Company paid the holders a total of $71 thousand of cash and issued 340 shares of the Company’s common stock.

During June 2011, the Company’s stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders for the ~~quarter~~three months ended ~~June~~September 30, ~~2011, and~~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 for and~~ been converted ~~as of March 31,~~on June 30, 2011, the note holders would have received ~~$480.0~~$479.9 million of cash and approximately ~~2.9~~1.8 million shares of the Company’s common stock, which was calculated over the last 20 trading days of June and valued at ~~$295.4 million at March 31, 2011.~~$158.8 million.

The Company utilizes commodity ~~derivatives~~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.~~

WTI oil prices. The following table sets forth the volumes in Bbls outstanding as of ~~March 31,~~June 30, 2011 under the Company’s oil derivative contracts and the weighted average oil prices per Bbl for those contracts:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average		First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production associated with derivatives (Bbls):
2011 – Swap contracts
Volume				750		750		750		750						750		750		750
NYMEX price			$	77.25	$	77.25	$	77.25	$	77.25					$	77.25	$	77.25	$	77.25

2011 – Collar contracts
Volume				2,000		2,000		2,000		2,000						2,000		2,000		2,000
NYMEX price:
Ceiling			$	170.00	$	170.00	$	170.00	$	170.00					$	170.00	$	170.00	$	170.00
Floor			$	115.00	$	115.00	$	115.00	$	115.00					$	115.00	$	115.00	$	115.00

2011 – Collar contracts with short puts
Volume				32,000		32,000		32,000		32,000						32,000		32,000		32,000
NYMEX price:
Ceiling			$	99.33	$	99.33	$	99.33	$	99.33					$	99.33	$	99.33	$	99.33
Floor			$	73.75	$	73.75	$	73.75	$	73.75					$	73.75	$	73.75	$	73.75
Short put			$	59.31	$	59.31	$	59.31	$	59.31					$	59.31	$	59.31	$	59.31

2012 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	79.32	$	79.32	$	79.32	$	79.32	$	79.32	$	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		37,000		37,000		37,000		37,000		37,000		36,000		36,000		36,000		36,000		36,000
NYMEX price:
Ceiling	$	118.34	$	118.34	$	118.34	$	118.34	$	118.34	$	117.99	$	117.99	$	117.99	$	117.99	$	117.99
Floor	$	80.41	$	80.41	$	80.41	$	80.41	$	80.41	$	80.42	$	80.42	$	80.42	$	80.42	$	80.42
Short put	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00

2013 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02

2013 – Collar contracts with short puts
2013 – Collar contracts with short puts (a)
Volume		21,250		21,250		21,250		21,250		21,250		21,250		21,250		21,250		21,250		21,250
NYMEX price:
Ceiling	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38
Floor	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18
Short put	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18

2014 – Collar contracts with short puts
2014 – Collar contracts with short puts (a)
Volume		12,000		12,000		12,000		12,000		12,000		12,000		12,000		12,000		12,000		12,000
NYMEX price:
Ceiling	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16
Floor	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92
Short put	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92

Natural gas liquids prices. All material physical sales contracts governing the Company’s NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities’ NGL product component prices.

The following table sets forth the volumes in Bbls outstanding as of ~~March 31,~~June 30, 2011 under the Company’s NGL derivative contracts and the weighted average NGL prices per Bbl for those contracts:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average		First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production associated with derivatives (Bbls):
2011 – Swap contracts
Volume				1,150		1,150		1,150		1,150						1,150		1,150		1,150
Blended index price			$	51.38	$	51.50	$	51.50	$	51.46					$	51.50	$	51.50	$	51.50

2011 – Collar contracts
Volume				2,650		2,650		2,650		2,650						2,650		2,650		2,650
Index price:
Ceiling			$	64.23	$	64.23	$	64.23	$	64.23					$	64.23	$	64.23	$	64.23
Floor			$	53.29	$	53.29	$	53.29	$	53.29					$	53.29	$	53.29	$	53.29

2012 – Swap contracts
Volume		750		750		750		750		750		750		750		750		750		750
Index price	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03

Gas prices.All material physical sales contracts governing the Company’s gas production are tied directly or indirectly to regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and reduce basis risk between NYMEX ~~Henry Hub~~HH prices and actual index prices ~~upon~~at which the gas is sold. The following table sets forth the volumes in MMBtus outstanding as of ~~March 31,~~June 30, 2011 under the Company’s gas derivative contracts and the weighted average gas prices per MMBtu for those contracts:


	First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Outstanding Average			First Quarter	Second Quarter	Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production associated with derivatives (MMBtus):
2011 – Swap contracts
Volume				117,500			117,500			117,500			117,500					117,500			117,500			117,500
NYMEX price			$	6.13		$	6.13		$	6.13		$	6.13				$	6.13		$	6.13		$	6.13

2011 – Collar contracts with short puts
Volume				200,000			200,000			200,000			200,000					200,000			200,000			200,000
NYMEX price:
Ceiling			$	8.55		$	8.55		$	8.55		$	8.55				$	8.55		$	8.55		$	8.55
Floor			$	6.32		$	6.32		$	6.32		$	6.32				$	6.32		$	6.32		$	6.32
Short put			$	4.88		$	4.88		$	4.88		$	4.88				$	4.88		$	4.88		$	4.88

2011 – Basis swap contracts
Volume				153,500			143,500			143,500			146,809					143,500			143,500			143,500
Price differential			$	(0.53	)	$	(0.56	)	$	(0.56	)	$	(0.55	)			$	(0.56	)	$	(0.56	)	$	(0.56	)

2012 – Swap contracts
Volume		105,000		105,000			105,000			105,000			105,000
NYMEX price	$	5.82	$	5.82		$	5.82		$	5.82		$	5.82

2012 – Collar contracts
Volume		65,000		65,000			65,000			65,000			65,000
NYMEX price:
Ceiling	$	6.60	$	6.60		$	6.60		$	6.60		$	6.60
Floor	$	5.00	$	5.00		$	5.00		$	5.00		$	5.00

2012 – Collar contracts with short puts
Volume		190,000		190,000			190,000			190,000			190,000
NYMEX price:
Ceiling	$	7.96	$	7.96		$	7.96		$	7.96		$	7.96
Floor	$	6.12	$	6.12		$	6.12		$	6.12		$	6.12
Short put	$	4.55	$	4.55		$	4.55		$	4.55		$	4.55


2012 – 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		116,000			116,000			116,000			116,000			116,000			126,000			126,000			126,000			126,000			126,000
Price differential	$	(0.37	)	$	(0.37	)	$	(0.37	)	$	(0.37	)	$	(0.37	)	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)

2013 – Swap contracts
Volume		67,500			67,500			67,500			67,500			67,500			67,500			67,500			67,500			67,500			67,500
NYMEX price	$	6.11		$	6.11		$	6.11		$	6.11		$	6.11		$	6.11		$	6.11		$	6.11		$	6.11		$	6.11

2013 – Collar contracts
Volume		150,000			150,000			150,000			150,000			150,000			150,000			150,000			150,000			150,000			150,000
NYMEX price:
Ceiling	$	6.25		$	6.25		$	6.25		$	6.25		$	6.25		$	6.25		$	6.25		$	6.25		$	6.25		$	6.25
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	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			45,000			45,000			45,000			45,000			45,000
NYMEX price:
Ceiling	$	7.49		$	7.49		$	7.49		$	7.49		$	7.49		$	7.49		$	7.49		$	7.49		$	7.49		$	7.49
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50

2013 – Basis swap contracts
Volume		32,500			32,500			32,500			32,500			32,500			52,500			52,500			52,500			52,500			52,500
Price differential	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)

2014 – Swap contracts
Volume		50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000
NYMEX price	$	6.05		$	6.05		$	6.05		$	6.05		$	6.05		$	6.05		$	6.05		$	6.05		$	6.05		$	6.05

2014 – Collar contracts
Volume		140,000			140,000			140,000			140,000			140,000			140,000			140,000			140,000			140,000			140,000
NYMEX price:
Ceiling	$	6.44		$	6.44		$	6.44		$	6.44		$	6.44		$	6.44		$	6.44		$	6.44		$	6.44		$	6.44
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00

2014 – Collar contracts with short puts
Volume		50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	8.08		$	8.08		$	8.08		$	8.08		$	8.08		$	8.08		$	8.08		$	8.08		$	8.08		$	8.08
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50		$	4.50

2014 – Basis swap contracts
Volume		10,000			10,000			10,000			10,000			10,000			20,000			20,000			20,000			20,000			20,000
Price differential	$	(0.16	)	$	(0.16	)	$	(0.16	)	$	(0.16	)	$	(0.16	)	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)

2015 – Collar contracts
Volume		50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	7.92		$	7.92		$	7.92		$	7.92		$	7.92		$	7.92		$	7.92		$	7.92		$	7.92		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00		$	5.00

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

Interest rates.The following table sets forth as of ~~March 31,~~June 30, 2011 the notional amount of the Company’s debt under outstanding fixed-for-variable interest rate swap contracts, the weighted average fixed annual interest rate and termination date for those contracts:

Type

Notional
Amount

Weighted
Average Fixed
Interest Rate

Termination
Date

Notional
Amount

Weighted
Average Fixed
Interest Rate

Termination
Date

(in thousands)

Fixed-for-variable

400,000

2.87 percent

July 2016

400,000

2.87 percent

July 2016

Fixed-for-variable

70,000

3.23 percent

March 2017

70,000

3.23 percent

March 2017

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

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


Fair Value of Derivative Instruments as of March 31, 2011
Fair Value of Derivative Instruments as of June 30, 2011										Fair Value of Derivative Instruments as of June 30, 2011
		Asset Derivatives (a)				Liability Derivatives (a)					Asset Derivatives (a)			Liability Derivatives (a)
Type		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value			Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
				(in thousands)				(in thousands)				(in thousands)			(in thousands)

Derivatives not designated as hedging instruments
Commodity price derivatives			Derivatives - current	$	145,952		Derivatives - current	$	183,747		Derivatives - current	$	153,812	Derivatives - current	$	87,944
Interest rate derivatives			Derivatives - current		11,810		Derivatives - current		—		Derivatives - current		12,253	Derivatives - current		—
Commodity price derivatives			Derivatives - noncurrent		118,591		Derivatives - noncurrent		190,856		Derivatives - noncurrent		135,927	Derivatives - noncurrent		114,334
Interest rate derivatives			Derivatives - noncurrent		9,306		Derivatives - noncurrent		10,745		Derivatives - noncurrent		17,870	Derivatives - noncurrent		5,177

Total derivatives not designated as hedging instruments					285,659				385,348
												$	319,862		$	207,455
Total derivatives				$	285,659			$	385,348


Fair Value of Derivative Instruments as of December 31, 2010	Fair Value of Derivative Instruments as of December 31, 2010									Fair Value of Derivative Instruments as of December 31, 2010
		Asset Derivatives (a)				Liability Derivatives (a)					Asset Derivatives (a)			Liability Derivatives (a)
Type		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value			Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
				(in thousands)				(in thousands)				(in thousands)			(in thousands)

Derivatives not designated as hedging instruments
Commodity price derivatives			Derivatives - current	$	167,406		Derivatives - current	$	87,741		Derivatives - current	$	167,406	Derivatives - current	$	87,741
Interest rate derivatives			Derivatives - current		11,903		Derivatives - current		886		Derivatives - current		11,903	Derivatives - current		886
Commodity price derivatives			Derivatives - noncurrent		152,731		Derivatives - noncurrent		64,829		Derivatives - noncurrent		152,731	Derivatives - noncurrent		64,829
Interest rate derivatives			Derivatives - noncurrent		15,762		Derivatives - noncurrent		9,227		Derivatives - noncurrent		15,762	Derivatives - noncurrent		9,227

Total derivatives not designated as hedging instruments					347,802				162,683
												$	347,802		$	162,683
Total derivatives				$	347,802			$	162,683


Derivatives in Cash Flow Hedging Relationships								Location of Gain/(Loss) Reclassified from AOCI into Earnings		Amount of Gain/(Loss) Reclassified from AOCI into Earnings
										Three Months Ended June 30,						Six Months Ended June 30,
										2011			2010			2011			2010
										in thousands
Interest rate derivatives									Interest expense	$	(69	)	$	(312	)	$	(137	)	$	(1,370	)
Interest rate derivatives									Derivative gains (losses), net		—			(1,523	)		—			(2,665	)
Commodity price derivatives									Oil and gas revenue		8,208			22,532			16,332			45,658

Total										$	8,139		$	20,697		$	16,195		$	41,623


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives		Amount of Gain (Loss) Recognized in Earnings on Derivatives					Location of Gain (Loss) Recognized in Earnings on Derivatives		Amount of Gain (Loss) Recognized in Earnings on Derivatives
			Three Months Ended March 31,							Three Months Ended June 30,						Six Months Ended June 30,
			2011			2010				2011			2010			2011			2010
			(in thousands)
										(in thousands)
Interest rate derivatives		Derivative gains (losses), net	$	(2,152	)	$	11,399		Derivative gains (losses), net	$	14,575		$	26,517		$	12,423		$	37,916
Commodity price derivatives		Derivative gains (losses), net		(242,280	)		255,219		Derivative gains (losses), net		214,903			152,534			(27,377)			407,753

Total			$	(244,432	)	$	266,618			$	229,478		$	179,051		$	(14,954)		$	445,669

AOCI - Hedging. As of ~~March 31,~~June 30, 2011 and December 31, 2010, AOCI -– Hedging represented net deferred gains of ~~$3.4~~$2.9 million and $7.4 million, respectively. The AOCI -– Hedging balance as of ~~March 31,~~June 30, 2011 was comprised of ~~$21.6~~$13.4 million of net deferred gains on the effective portions of discontinued commodity hedges, ~~$1.9~~$1.8 million of net deferred losses on the effective portions of discontinued interest rate hedges and ~~$5.9~~$1.8 million of associated net deferred tax provisions, reduced by ~~$10.4~~$6.9 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.

During the twelve months ending ~~March 31,~~June 30, 2012, the Company expects to reclassify ~~$24.0~~$15.0 million of AOCI – Hedging net deferred gains to oil revenues (including ~~$10.4~~$7.0 million related to noncontrolling interests) and ~~$291~~$299 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify ~~$8.5~~$2.8 million of net deferred income tax provisions associated with hedge derivatives during the twelve months ending ~~March 31,~~June 30, 2012 from AOCI -– Hedging to income tax expense. For the remaining ~~nine~~six months of 2011, the Company expects to reclassify deferred gains on discontinued commodity hedges of ~~$24.8~~$16.6 million to oil revenues. During 2012, the Company expects to reclassify deferred losses on commodity hedges of $3.2 million to oil revenues. The aforementioned ~~$1.9~~$1.8 million of net deferred hedge losses on the effective portion of interest rate hedges will be transferred from AOCI-Hedging to interest expense ratably through April 2018.

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

The following table summarizes the Company’s asset retirement obligation activity during the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010
	(in thousands)						(in thousands)

Beginning asset retirement obligations	$	152,291		$	166,434		$	154,689		$	142,270		$	152,291		$	166,434
Liabilities assumed in acquisitions		6			—			—			6			6			6
New wells placed on production		671			278			1,404			4,365			2,075			4,644
Changes in estimates		300			—			(179	)		—			121			—
Disposition of wells		(81	)		(26,248	)		(367	)		(3,291	)		(448	)		(29,540	)
Liabilities settled		(1,234	)		(1,154	)		(6,235	)		(8,801	)		(7,469	)		(9,955	)
Accretion of discount from continuing operations		2,655			2,859			2,658			2,529			5,313			5,388
Accretion of discount from discontinued operations		81			101			—			103			81			204


Ending asset retirement obligations	$	154,689		$	142,270		$	151,970		$	137,181		$	151,970		$	137,181

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of ~~March 31,~~June 30, 2011 and December 31, 2010, the current portions of the Company’s asset retirement obligations were ~~$19.4~~$14.9 million and $19.9 million, respectively.

As of ~~March 31,~~June 30, 2011 and December 31, 2010, the Company had ~~$7.2~~$7.0 million and $7.4 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities in the accompanying consolidated balance sheets. These obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of ~~March 31,~~June 30, 2011 or December 31, 2010. ~~Other than participants in the Company’s retirement plan, the~~The participants of ~~these~~the predecessor plans are not current employees of the Company.

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the three and six months ended ~~March 31,~~June 30, 2011 and ~~March 31,~~ 2010:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010
	(in thousands)						(in thousands)

Beginning accumulated postretirement benefit obligations	$	7,408		$	9,075		$	7,231		$	8,951		$	7,408		$	9,075
Net benefit payments		(316	)		(312	)		(375	)		(272	)		(691	)		(584	)
Service costs		61			80			61			81			122			161
Net actuarial losses								—			100			—			100
Accretion of interest		78			108			79			108			157			216


Ending accumulated postretirement benefit obligations	$	7,231		$	8,951		$	6,996		$	8,968		$	6,996		$	8,968

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 ~~and negatively~~ 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.

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 ~~total~~ net income attributable to common stockholders.

During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, ~~such as during the three months ended March 31, 2011,~~ securities or other contracts to issue common stock would be dilutive to loss per share from continuing operations; therefore, conversion into common stock is assumed not to occur.

The following tables reconcile the Company’s net income ~~(loss)~~ from continuing operations, income (loss) from discontinued operations and ~~total~~ 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 ~~(loss)~~ per share amounts for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:

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

The following tables provide the Company’s geographic operating segment data for the three and six months ended ~~March 31,~~June 30, 2011 and 2010. Geographic operating segment income tax (provisions) benefits have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The “Headquarters” table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis.


	United States			South Africa			Headquarters			Consolidated Total			United States			South Africa			Headquarters			Consolidated Total
	(in thousands)												(in thousands)

Three Months Ended March 31, 2011
Three Months Ended June 30, 2011
Revenues and other income:
Oil and gas	$	475,729		$	21,401		$	—		$	497,130		$	562,411		$	21,520		$	—		$	583,931
Interest and other		—			—			32,687			32,687			13,725			—			4,729			18,454
Loss on disposition of assets, net		—			—			(2,191	)		(2,191	)		—			—			(296	)		(296	)

		475,729			21,401			30,496			527,626			576,136			21,520			4,433			602,089

Costs and expenses:
Oil and gas production		98,835			1,096			—			99,931			101,741			714			—			102,455
Production and ad valorem taxes		33,296			—			—			33,296			35,864			—			—			35,864
Depletion, depreciation and amortization		116,540			13,685			10,148			140,373			127,864			13,536			12,498			153,898
Exploration and abandonments		17,485			158			—			17,643			19,731			183			—			19,914
General and administrative		—			—			44,106			44,106			—			—			44,644			44,644
Accretion of discount on asset retirement obligations		2,044			611			—			2,655			2,047			611			—			2,658
Interest		—			—			45,227			45,227			—			—			45,768			45,768
Hurricane activity, net		71			—			—			71			(2	)		—			—			(2	)
Derivative losses, net		—			—			244,432			244,432
Derivative gains, net														—			—			(229,478	)		(229,478	)
Other		5,159			—			12,722			17,881			5,410			—			8,978			14,388

		273,430			15,550			356,635			645,615			292,655			15,044			(117,590	)		190,109

Income (loss) from continuing operations before income taxes		202,299			5,851			(326,139	)		(117,989	)
Income tax benefit (provision)		(74,851	)		(1,638	)		123,640			47,151
Income from continuing operations before income taxes														283,481			6,476			122,023			411,980
Income tax provision														(104,888	)		(1,813	)		(37,995	)		(144,696	)

Income (loss) from continuing operations	$	127,448		$	4,213		$	(202,499	)	$	(70,838	)
Income from continuing operations													$	178,593		$	4,663		$	84,028		$	267,284


	United States			South Africa			Headquarters			Consolidated Total			United States			South Africa			Headquarters			Consolidated Total
	(in thousands)												(in thousands)

Three Months Ended March 31, 2010
Three Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	446,664		$	25,381		$	—		$	472,045		$	401,540		$	20,502		$	—		$	422,042
Interest and other		—			—			18,008			18,008			998			—			15,954			16,952
Gain (loss) on disposition of assets, net		17,419			—			(476	)		16,943
Gain on disposition of assets, net														7,560			—			85			7,645

		464,083			25,381			17,532			506,996			410,098			20,502			16,039			446,639

Costs and expenses:
Oil and gas production		85,324			776			—			86,100			93,116			896			—			94,012
Production and ad valorem taxes		27,061			—			—			27,061			25,338			—			—			25,338
Depletion, depreciation and amortization		115,505			21,897			7,026			144,428			117,859			18,442			8,008			144,309
Exploration and abandonments		16,776			72			—			16,848			22,689			54			—			22,743
General and administrative		—			—			38,315			38,315			—			—			40,433			40,433
Accretion of discount on asset retirement obligations		2,237			622			—			2,859			1,907			622			—			2,529
Interest		—			—			47,523			47,523			—			—			45,368			45,368
Hurricane activity, net		(7,410	)		—			—			(7,410	)		5,184			—			—			5,184
Derivative gains, net		—			—			(265,476	)		(265,476	)		—			—			(177,528	)		(177,528	)
Other		10,281			—			5,665			15,946			10,270			—			3,923			14,193

		249,774			23,367			(166,947	)		106,194			276,363			20,014			(79,796	)		216,581

Income from continuing operations before income taxes		214,309			2,014			184,479			400,802			133,735			488			95,835			230,058
Income tax provision		(79,294	)		(564	)		(64,149	)		(144,007	)		(49,482	)		(137	)		(33,601	)		(83,220	)

Income from continuing operations	$	135,015		$	1,450		$	120,330		$	256,795		$	84,253		$	351		$	62,234		$	146,838

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

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

The following table provides information about changes in the deferred revenue carrying values of the ~~Company’s~~Company's VPP for the ~~three~~six months ended ~~March 31,~~June 30, 2011 (in thousands):


Deferred revenue at December 31, 2010	$	87,020		$	87,020
Less: 2011 amortization		(11,083	)		(22,290	)

Deferred revenue at March 31, 2011	$	75,937
Deferred revenue at June 30, 2011				$	64,730

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


Remaining 2011	$	33,866	$	22,659
2012		42,071	$	42,071

	$	75,937

For the three and six months ended ~~March 31,~~June 30, 2011, the Company recorded ~~$2.2~~$296 thousand and $2.5 million of net losses on disposition of assets from continuing operations, respectively, as compared to ~~$16.9~~$7.6 million and $24.6 million, respectively, of net gains from continuing operations for the three and six months ended ~~March 31,~~June 30, 2010.

The Company’s ~~$2.2 million~~ net ~~loss~~losses during the three and six months ended ~~March 31,~~June 30, 2011 ~~was~~are primarily associated with sales of excess materials and supplies inventory. During the three and six months ended ~~March 31,~~June 30, 2010, the Company’s net ~~gain~~gains are primarily attributable to the Company’s Eagle Ford Shale joint venture transaction that was ~~primarily associated with certain~~completed during June 2010, and the sale of proved and unproved oil and gas properties ~~divested~~ in the Uinta/Piceance area.

See Note Q for information about the Company’s ~~gain~~gains and losses during the three and six months ended ~~March 31,~~June 30, 2011 from the sale of its Tunisia subsidiaries ~~representing~~that are included in discontinued operations.

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


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010		2011		2010
	(in thousands)				(in thousands)

Alaskan Petroleum Production Tax credits (a)	$	27,452	$	14,248	$	—	$	13,613	$	27,452	$	27,861
Drilling and servicing margin		2,878		510
Third-party income from vertical integration services (b)						13,725		998		16,603		1,507
Other income						1,912		1,131		2,913		1,783
Eagle Ford Shale land fees						1,802		—		1,802		—
Deferred compensation plan income		867		510		299		174		1,166		684
Other income		1,002		691
Equity interest in income of unconsolidated affiliate		298		—		502		—		801		—
Interest income		190		384		214		92		404		476
Sales and other tax refunds						—		944		—		984
Insurance claim recovery		—		1,665		—		—		—		1,665

Total interest and other income	$	32,687	$	18,008	$	18,454	$	16,952	$	51,141	$	34,960


	Three Months Ended March 31,				Three Months Ended June 30,						Six Months Ended June 30,
	2011		2010		2011			2010			2011			2010
	(in thousands)				(in thousands)

Transportation commitment charge (a)	$	5,272	$	—	$	5,688		$	—		$	10,960		$	—
Excess and terminated rig related costs (b)		5,159		10,281
Above market drilling rig related costs (b)						5,410			10,270			10,569			20,551
Other		2,494		650		1,909			2,617			4,193			3,170
Loss on extinguishment of debt		2,367		—		—			—			2,367			—
Contingency and environmental accrual adjustments		1,295		153		1,587			94			2,882			247
Cancelled well costs		991		—
Cancelled well costs (recoveries)						(442	)		(126	)		759			(29	)
Inventory impairment (c)		285		1,557		302			13			587			1,570
Bad debt expense		18		224
Tax penalties						1,749			—			1,749			—
Bad debt recoveries						(1,815	)		(254	)		(1,797	)		(30	)
Well servicing operations (d)		—		3,081		—			1,579			—			4,660

Total other expense	$	17,881	$	15,946	$	14,388		$	14,193		$	32,269		$	30,139

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 ~~$845.2~~$853.7 million, including normal post-closing adjustments, resulting in a pretax gain of ~~$649.9~~$645.3 million. ~~Accordingly,~~During the three months ended June 30, 2011, the Company reduced the net gain on the transaction by $4.6 million. The historical results of operations of Pioneer Tunisia have been classified as discontinued operations herein. ~~The net cash proceeds from~~

During the ~~sale of Pioneer Tunisia were determined in accordance with~~six months ended June 30, 2011 and 2010, the ~~sale and purchase agreement that~~BOEMRE paid the Company ~~entered into~~$2.0 million and $35.3 million, respectively, of interest on excess royalty payments associated with properties that were sold by the ~~purchaser, which provides~~Company during 2006. Accordingly, the interest income is classified as income from discontinued operations. See Note B for certain customary adjustments for matters occurring after the effective date of the sale, such as capital contributions and distributions, and working capital adjustments. Adjustments to net cash proceeds involve management’s best estimateadditional information about the realizable value of working capital items, including that the amounts are reasonably assured of collection. Differences between actual working capital amounts and management’s estimates recorded as of March 31, 2011, if any, will be recorded as income or loss from discontinued operations in future periods.BOEMRE payments.

The following table represents the components of the Company’s discontinued operations for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010
	(in thousands)						(in thousands)

Revenues and other income:
Oil and gas	$	22,130		$	35,752		$	—		$	40,096		$	22,130		$	75,848
Interest and other ~~(a)~~		4,568			1,795			18			42,619			4,586			44,414
Gain on disposition of assets, net		649,872			—
Gain (loss) on disposition of assets, net (a)								(4,574	)		—			645,298			—

		676,570			37,547			(4,556	)		82,715			672,014			120,262

Costs and expenses:
Oil and gas production		2,126			3,616			—			3,278			2,126			6,894
Depletion, depreciation and amortization ~~(b)~~(a)		—			6,340			—			6,006			—			12,346
Exploration and abandonments		2,554			3,950			1,692			4,379			4,246			8,329
General and administrative		6,619			2,633			2,279			1,940			8,898			4,573
Accretion of discount on asset retirement obligations ~~(b)~~(a)		81			101			—			103			81			204
Other		1,182			629			675			533			1,857			1,161

		12,562			17,269			4,646			16,239			17,208			33,507

Income from discontinued operations before income taxes		664,008			20,278
Current tax (provision) benefit		(7,574	)		444
Deferred tax provision (b)		(241,792	)		(16,911	)
Income (loss) from discontinued operations before income taxes								(9,202	)		66,476			654,806			86,755
Current tax provision (b)								(1,963	)		(5,737	)		(9,537	)		(5,294	)
Deferred tax (provision) benefit (a) (b)								9,581			(18,888	)		(232,211	)		(35,799	)

Income from discontinued operations	$	414,642		$	3,811
							$	(1,584	)	$	41,851		$	413,058		$	45,662

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

The Company’s financial and operating performance for the ~~first~~second quarter of 2011 included the following highlights:

Based on current estimates, the Company expects that ~~second~~third quarter 2011 production will average ~~116~~125,000 to ~~121 MBOEPD.~~131,000 BOEPD. The Company’s South Africa production was shut in during late-July due to unplanned third-party gas-to-liquids plant downtime. The third quarter production guidance does not reflect the potential for this downtime to extend beyond four weeks, which is a possibility.

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

Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and administrative expense is expected to be $45 million to ~~$49~~$50 million. Interest expense is expected to be $44 million to ~~$47~~$48 million, and other expense is expected to be $20 million to ~~$25~~$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 ~~second~~third quarter effective income tax rate is expected to range from 35 percent to 45 percent, assuming current capital spending plans and no significant mark-to-market changes in the Company’s derivative position. Cash income taxes are expected to range from $5 million to $10 million, principally related to South African income taxes.

The following table summarizes the Company’s average daily oil, NGL, gas and total production by asset area during the ~~three~~six months ended ~~March 31,~~June 30, 2011:


	Oil (Bbls)		NGLs (Bbls)		Gas (Mcf)		Total (BOE)		Oil (Bbls)		NGLs (Bbls)		Gas (Mcf)		Total (BOE)
United States:
Permian Basin		23,608		10,278		44,043		41,226		23,321		10,748		45,640		41,676
Raton Basin										—		—		161,822		26,970
Mid-Continent		3,584		6,134		51,301		18,268		3,948		7,062		52,005		19,677
Raton Basin		—		—		162,036		27,006
Barnett Shale		147		884		7,399		2,264
South Texas		100		—		46,251		7,809		106		—		46,664		7,884
Eagle Ford Shale		1,741		1,348		14,099		5,439		2,403		1,497		17,269		6,779
Alaska		4,744		—		—		4,744		4,864		—		—		4,864
Barnett Shale										258		941		7,841		2,506
Other		2		1		40		10		4		3		54		15

		33,926		18,645		325,169		106,766		34,904		20,251		331,295		110,371

South Africa		526		—		23,537		4,449		571		—		23,867		4,549

Total Worldwide		34,452		18,645		348,706		111,215		35,475		20,251		355,162		114,920

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

The following table summarizes by geographic area the Company’s finding and development costs incurred from continuing operations during the ~~three~~six months ended ~~March 31,~~June 30, 2011:


										Asset				Acquisition Costs					Exploration Costs		Development Costs			Asset Retirement Obligations			Total
	Acquisition Costs					Exploration		Development		Retirement				Acquisition Costs
	Proved		Unproved			Costs		Costs		Obligations		Total		Proved		Unproved
	(in thousands)													(in thousands)

United States:
Permian Basin	$	3,123	$	3,742		$	15,269	$	210,294	$	594	$	233,022	$	4,733	$	5,130		$	34,947		$	490,364		$	1,212		$	536,386
Raton Basin															82		(53	)		3,596		19,689			120			23,434
Mid-Continent		3		(2	)		314		2,864		—		3,179		12		107			3,135		6,421			27			9,702
Raton Basin		50		(55	)		2,112		4,310		—		6,417
Barnett Shale		—		1,574			41,273		1,831		78		44,756
South Texas		—		157			5,428		6,948		3		12,536		—		1,146			6,051		10,080			3			17,280
Eagle Ford Shale		—		5,552			19,232		1,199		2		25,985		—		18,737			53,040		2,367			6			74,150
Alaska		—		—			1,526		28,200		300		30,026		—		—			5,561		50,731			866			57,158
Barnett Shale															—		14,676			119,726		4,848			147			139,397
Other		—		409			700		—		—		1,109		—		420			3,570		—			—			3,990

		3,176		11,377			85,854		255,646		977		357,030		4,827		40,163			229,626		584,500			2,381			861,497

South Africa		—		—			158		—		—		158		—		—			341		—			(179	)		162

Total Worldwide	$	3,176	$	11,377		$	86,012	$	255,646	$	977	$	357,188	$	4,827	$	40,163		$	229,967	$	584,500		$	2,202		$	861,659

The following table summarizes the Company’s development and exploration/extension drilling activities for the ~~three~~six months ended ~~March 31,~~June 30, 2011:

Permian Basin ~~area~~.area. During the first ~~quarter~~half of 2011, the Company drilled ~~141~~278 wells in the Spraberry ~~field.~~field, of which 273 were successful. The Company ~~is currently utilizing 32~~had 35 rigs ~~with~~operating as of June 30, 2011, and plans to increase its rig count to ~~35 by mid-2011 and to~~ 45 rigs ~~in 2012.~~by the end of the year. The Company’s drilling program continues to include the deepening of wells to the Lower Wolfcamp formation, and in certain drilling areas, ~~down~~ to the Strawn interval with positive production results. In addition, the Company has recently drilled two successful wells to the Atoka ~~formation.~~interval and one successful well to the Mississippian interval.

The Company continues to expand its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has increased its owned drilling rigs to 14 and has ~~three~~four Company-owned fracture stimulation fleets currently ~~operating.~~operating in the Spraberry field. One additional fracture stimulation fleet ~~has been delivered~~is being built and is expected to ~~start operating in early May and another fleet is being built, with delivery scheduled~~be operational during the fourth quarter of 2011. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, the Company has contracted for ~~its~~ forecasted fracture stimulation sand supply requirements through 2015, ~~its~~ tubular and pumping unit requirements through 2012 and ~~is negotiating an agreement with a third-party to supply~~ well cementing services through 2016.

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

The Company has completed ~~thirty-eight~~85 wells in the Strawn interval since the testing program began in the first quarter of 2010. Initial peak production rates from this interval, when tested alone, have averaged 70 BOEPD. Early results suggest an increase of up to 20 percent in cumulative production over the first 12 months compared to production from offset Lower Wolfcamp wells over the same time period. The incremental cost per well for this deeper drilling and one additional ~~frac~~fracture stimulation stage is approximately $60 thousand. The Company believes that the Strawn interval is prospective in 40 percent of its Spraberry acreage and expects to ~~target the Strawn~~complete this interval in 5025 percent of the wells in its 2011 Spraberry drilling program.

The Company ~~is currently completing its first~~has completed two ~~vertical~~ Atoka ~~wells.~~wells in 2011. The initial peak production rate from this interval, when tested alone, averaged 150 BOEPD. The Company plans to test the Atoka interval for ~~two~~up to six months and then comingle this production with production from upper intervals in the Spraberry and Wolfcamp zones. The incremental cost to drill an Atoka well is estimated to be ~~$500~~$250 thousand to $750 thousand, with the higher end of the range reflecting ~~deeper drilling and adding~~the addition of an intermediate casing string and either a water or carbon dioxide fracture stimulation. The Company plans to drill approximately 10 Atoka wells during 2011 to further evaluate the interval’s development potential. The Company believes that the Atoka interval is prospective in 25 percent to 50 percent of its Spraberry acreage.

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

The Company has also ~~commenced a program to test~~dedicated one drilling rig towards research and development of horizontal drilling applications in multiple intervals of the Spraberry field. The first ~~two wells in~~well to test the ~~program have been drilled and completed. Both wells had 4,000-foot laterals~~Lower Wolfcamp shale interval was a 3,500-foot lateral with a 15-stage fracture stimulation ~~completions.~~

completion. The ~~first horizontal well was drilled in a Wolfcamp carbonate interval. Microseismic tests indicated the completion did not effectively stimulate the targeted zone. As a result, the~~ well had an initial production rate of ~~approximately 100~~200 barrels of oil per day (“BOPD”)~~, but the production declined more quickly~~ and 120 MCFPD with less than expected. Given the ineffective stimulation, the Company does not view this well as a representative test of the potential for a horizontal well in this interval and plans to test additional horizontal wells in this interval.

The second horizontal well targeted the Lower Wolfcamp shale interval. It was completed in late April. Microseismic tests indicated the successful stimulation of the interval. The well is currently unloading the fracture stimulation water, and with 3050 percent of the load water ~~unloaded, the well is producing at an early test rate of 150 BOPD.~~recovered.

The Company plans to drill six ~~to eight~~ additional horizontal ~~wells. These~~ wells ~~will target~~during the ~~Lower Wolfcamp shale,~~second half of 2011, targeting the Tippett shale (Middle Wolfcamp)~~, Wolfcamp carbonate~~ and Jo Mill (Middle Spraberry) intervals.

~~Water injection was initiated in the third quarter~~ The first Tippett shale well, with a planned lateral section of 2010 on the Company’s 7,000-acre waterflood project in the Upper Spraberry interval. Early results are encouraging, as the production decline from 110 producing wells in the surveillance area continues to flatten. Early production response has been observed in several wells6,000 feet and ~~there has been no premature water breakthrough. Based on the results of historical waterflood projects, an ultimate uptick in production of 50 percent from the flooded Upper Spraberry interval~~a 30-stage fracture stimulation completion, is ~~expected.~~currently being drilled.

The Company continues to test downspacing in the Spraberry field from 40 acres to 20 acres. Eighteen 20-acre wells were drilled in 2010, ~~with 14~~and all of these wells are on production. These 20-acre wells are capturing pay from the Lower Wolfcamp, Strawn and shale/silt intervals, with encouraging results. The Company plans to drill ~~twenty~~10 to 20 additional 20-acre downspaced wells in 2011.

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

The Company has drilled 50and completed 39 horizontal Eagle Ford Shale wells during the first six months of 2011. On June 30, 2011, 23 Eagle Ford Shale wells were in ~~aggregate through the end~~progress or awaiting completion and hookup. Completion of wells in the first quarter of ~~2011. Twenty-four of the wells are producing and, of the remaining 26 wells, five are completed and awaiting hookup. Completion of the remaining 21 wells has~~2011 had been ~~slower than anticipated~~delayed primarily due to limited third-party fracture stimulation fleet availability.

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

The unconsolidated affiliate formed by the Company to operate gathering facilities in the Eagle Ford Shale area, EFS Midstream, is obligated to construct midstream assets in the Eagle Ford Shale area. Construction of the midstream assets is underway, with the majority of the construction expected to be completed by 2013. ~~Four~~Five of the 12 planned central gathering plants (“CGPs”) were completed as of ~~March 31, 2011, and a fifth was completed during April~~June 30, 2011. EFS Midstream plans to build three additional CGPs during the remainder of 2011, including two during the third quarter of 2011. As construction of CGPs is completed, EFS Midstream will provide gathering, treating and transportation services for the Company during a 20-year contractual term. The Company has invested $155.7 million of capital in EFS Midstream, $82.9 million of which was contributed during the six months ended June 30, 2011. During June 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that will be used to fund infrastructure investments that are in excess of operating cash flow.

Alaska.The Company owns a 70 percent working interest and is the operator of the Oooguruk development project. The Company has drilled 1112 production wells and ~~six~~seven injection wells of the estimated 17 production and 16 injection wells planned to fully develop this project. ~~In addition, the~~The Company drilled a horizontal exploration well in the Torok formation during 2010 and ~~recently concluded~~completed a second Torok well in the first quarter of 2011. Based on the performance to date, the Company plans to drill and fracture stimulate an additional Torok well in early 2012 to further evaluate the productivity of the formation and the feasibility of future development expansion.

Barnett Shale. During the first ~~quarter~~half of 2011, the Company operated two ~~rigs. Since beginning~~ drilling ~~activities~~rigs and drilled and completed 16 Barnett Shale wells. The Company plans to increase its drilling rigs in the Barnett Shale to four rigs during 2012. A Pioneer-owned fracture stimulation fleet commenced operating in the Barnett Shale during the ~~fourth~~second quarter of ~~2010, the Company has drilled 24~~2011. As of June 30, 2011, 27 Barnett Shale wells ~~of which ten wells have been completed, with five wells currently producing.~~were in progress. In addition, the Company has acquired 160 square miles of 3-D seismic covering its acreage and expects to increase this coverage ~~to 200~~by 190 square miles by year end. The Company is utilizing the 3-D seismic to high-grade future drilling location selections.

Oil and gas revenues. Oil and gas revenues totaled ~~$497.1~~$583.9 million and $1.1 billion for the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~$472.0~~$422.0 million and $894.1 million for the same respective ~~period~~periods of 2010.

The increase in oil and gas revenues during the three months ended ~~March 31,~~June 30, 2011, as compared to the same period of 2010, is reflective of increases in worldwide average reported oil, NGL and gas prices and United States oil,

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

During ~~February~~March 2011, the Company’s operations in Texas, Kansas and Colorado were disrupted by extremely cold temperatures and substantial ice and snow accumulations. The Company experienced extensive pipeline freeze-ups, power outages and limited access to well locations. Drilling and completion operations in the Spraberry field and the Barnett Shale Combo play were also curtailed. In some cases, the Company’s operations were affected until early-March by the severe weather event.

~~In addition to the weather-related impacts,~~ a third-party fractionator for the Company’s Mid-Continent NGL production experienced a longer-than-anticipated ~~turnaround during March 2011.~~turnaround. As a result, the NGL production was inventoried in March and ~~will be~~was fractionated and sold during the second quarter of 2011. The impact of the ~~fractionators~~fractionator’s turnaround ~~delay decreased first~~increased second quarter NGL sales by approximately 1 MBOEPD.

The following table provides average daily sales volumes from continuing operations, by geographic area and in total, for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010		2011		2010
Oil (Bbls):
United States		33,926		25,803		35,872		27,447		34,904		26,630
South Africa		526		1,111		616		641		571		875

Worldwide		34,452		26,914		36,488		28,088		35,475		27,505

NGLs (Bbls):
United States		18,645		19,115		21,839		19,291		20,251		19,204

Gas (Mcf):
United States		325,169		346,248		337,354		333,916		331,295		340,048
South Africa		23,537		31,033		24,193		28,810		23,867		29,915

Worldwide		348,706		377,281		361,547		362,726		355,162		369,963

Total (BOE):
United States		106,766		102,627		113,937		102,391		110,371		102,508
South Africa		4,449		6,283		4,648		5,443		4,549		5,861

Worldwide		111,215		108,910		118,585		107,834		114,920		108,369

In the United States, average daily BOE sales volumes increased by ~~four~~11 percent and eight percent for the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to the same ~~period~~respective periods of 2010 due to results from the Company’s successful drilling programs and declines in scheduled VPP deliveries. For the three and six months ended ~~March 31,~~June 30, 2011, average South Africa daily BOE sales volumes decreased by 2915 percent ~~in South Africa,~~and 22 percent, respectively, as compared to the same respective ~~period~~periods of 2010, due to normal well decline rates. See “Third Quarter Outlook” for information about South Africa production curtailment due to unplanned third-party gas-to-liquid plant downtime.

During the three and six months ended ~~March 31,~~June 30, 2011, as compared to the three and six months ended ~~March 31,~~June 30, 2010, oil volumes delivered under the Company’s VPPs decreased by ~~46 percent.~~45 percent for each period. The Company completed its oil delivery obligations under one of the VPP agreements at the end of 2010.

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

The following table provides average reported prices (including transfers of deferred hedge gains and losses and the amortization of deferred VPP revenue) and average realized prices (excluding transfers of deferred hedge gains and losses and the amortization of deferred VPP revenue) by geographic area and in total, for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010		2011		2010
Average reported prices:
Oil (per Bbl):
United States	$	95.46	$	92.08	$	104.34	$	89.50	$	100.05	$	90.74
South Africa	$	106.38	$	77.58	$	104.86	$	76.88	$	105.56	$	77.32
Worldwide	$	95.62	$	91.48	$	104.35	$	89.21	$	100.13	$	90.31
NGL (per Bbl):
United States	$	42.17	$	41.82	$	48.16	$	34.40	$	45.42	$	38.07
Gas (per Mcf):
United States	$	3.88	$	5.16	$	4.11	$	3.87	$	4.00	$	4.52
South Africa	$	7.73	$	6.31	$	7.10	$	6.11	$	7.41	$	6.21
Worldwide	$	4.14	$	5.26	$	4.31	$	4.05	$	4.23	$	4.66
Total (per BOE)
United States	$	49.51	$	48.36	$	54.24	$	43.09	$	51.97	$	45.72
South Africa	$	53.45	$	44.89	$	50.88	$	41.39	$	52.13	$	43.25
Worldwide	$	49.67	$	48.16	$	54.11	$	43.01	$	51.97	$	45.58
Average realized prices:
Oil (per Bbl):
United States	$	89.17	$	73.60	$	98.39	$	72.53	$	93.93	$	73.05
South Africa	$	106.38	$	77.58	$	104.86	$	76.88	$	105.56	$	77.32
Worldwide	$	89.43	$	73.77	$	98.50	$	72.63	$	94.12	$	73.18
NGL (per Bbl):
United States	$	42.17	$	40.77	$	48.16	$	33.36	$	45.42	$	37.03
Gas (per Mcf):
United States	$	3.88	$	5.13	$	4.11	$	3.84	$	4.00	$	4.50
South Africa	$	7.73	$	6.31	$	7.10	$	6.11	$	7.41	$	6.21
Worldwide	$	4.14	$	5.23	$	4.31	$	4.02	$	4.23	$	4.63
Total (per BOE)
United States	$	47.51	$	43.42	$	52.37	$	38.25	$	50.03	$	40.83
South Africa	$	53.45	$	44.89	$	50.88	$	41.39	$	52.13	$	43.25
Worldwide	$	47.75	$	43.51	$	52.31	$	38.41	$	50.12	$	40.96

Derivative activities.The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts in order to (i) reduce the effect of price volatility on the commodities the Company produces, sells and ~~sells,~~consumes, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for the scheduled amortization of net deferred gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil revenues.

The following table provides the transfers of deferred hedge gains from AOCI-Hedging associated with oil, NGL and gas price cash flow hedges to oil, NGL and gas revenue for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010		2011		2010
	(in thousands)				(in thousands)
Increase to oil revenue from AOCI-Hedging transfers	$	8,124	$	20,417	$	8,208	$	19,792	$	16,332	$	40,209
Increase to NGL revenue from AOCI-Hedging transfers		—		1,799		—		1,820		—		3,619
Increase to gas revenue from AOCI-Hedging transfers		—		910		—		920		—		1,830

Total	$	8,124	$	23,126	$	8,208	$	22,532	$	16,332	$	45,658

Deferred revenue.During the three and six months ended ~~March 31,~~June 30, 2011, the Company’s amortization of deferred VPP revenue increased oil revenues by ~~$11.1~~$11.2 million and $22.3 million, respectively, as compared to an increase of ~~$22.5~~$22.6 million and $45.1 million during the same ~~period~~respective periods of 2010. See Note M of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s VPPs.

Interest and other income.Interest and other income for the three and six months ended ~~March 31,~~June 30, 2011 was ~~$32.7~~$18.5 million and $51.1 million, respectively, as compared to ~~$18.0~~$17.0 million and $35.0 million for the same ~~period~~respective periods in 2010. The ~~$14.7~~$1.5 million increase in interest and other income during the three months ended ~~March 31,~~June 30, 2011, as compared to the same period in 2010, was primarily due to a ~~$13.2~~$12.7 million increase in third-party income from vertical integration services and $1.8 million in Eagle Ford Shale land fee receipts, partially offset by a $13.6 million decrease in Alaskan Petroleum Production tax credit recoveries. The $16.1 million increase in interest and other income during the six months ended June 30, 2011, as compared to the same period in 2010, was primarily due to a $15.1 million increase in third-party income from vertical integration services and the aforementioned $1.8 million in Eagle Ford Shale land fees. See Note O of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding interest and other income.

Gain (Loss) on disposition of assets, net.The Company recorded net losses on the disposition of assets of ~~$2.2~~$296 thousand and $2.5 million during the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to net gains on the disposition of assets of ~~$16.9~~$7.6 million and $24.6 million for the three and six months ended ~~March 31, 2010.~~June 30, 2010, respectively. The ~~decrease in~~2011 net ~~gains is~~losses were primarily associated with sales of excess materials and supplies inventory. During the three and six months ended June 30, 2010, the Company recorded gains ~~from~~associated with the ~~first quarter 2010~~Company’s Eagle Ford Shale joint venture transaction and the sale of ~~certain~~ proved and unproved oil and gas properties in the Uinta/Piceance area. ~~The Company reported net losses on the sale of excess materials and supplies inventories during the three months ended March 31, 2011.~~ See Note N of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s gains and losses on dispositions of assets.

Oil and gas production costs. The Company recorded oil and gas production costs of ~~$99.9~~$102.5 million and $202.4 million during the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~$86.1~~$94.0 million and $180.1 million during the same ~~period~~respective periods of 2010. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company’s gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE from continuing operations ~~increased by 14 percent during~~for the three months ended ~~March 31,~~June 30, 2011 aswere consistent with the three months ended June 30, 2010, while they increased by six percent during the six months ended June 30, 2011 compared to the same period in 2010. The increase in United States production costs per BOE during the six months ended June 30, 2011 is primarily due to repairs associated with severe winter weather disruptions encountered during the first quarter of 2011 and inflation in well servicing costs, partially offset by the reduction in VPP delivery commitments. South Africa production costs per BOE increased during the three months ended March 31, 2011, as compared to the same respective periods of 2010 primarily due to the effects of sales volumes variations on the fixed components of South Africa production costs.

The following tables provide the components of the Company’s oil and gas production costs per BOE from continuing operations and total production costs per BOE from continuing operations by geographic area for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,					Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011			2010		2011		2010
Lease operating expenses	$	7.83	$	7.16		$	7.70		$	7.76	$	7.76	$	7.47
Third-party transportation charges		0.99		0.86			1.06			0.84		1.03		0.85
Net natural gas plant/gathering charges (credits)		0.39		(0.25	)		(0.25	)		0.31		0.06		0.03
Workover costs		0.78		1.01			0.99			0.67		0.89		0.84


Total production costs	$	9.99	$	8.78		$	9.50		$	9.58	$	9.74	$	9.19


						Three Months Ended June 30,					Six Months Ended June 30,
						2011			2010		2011		2010
United States	$	10.28	$	9.24		$	9.81		$	10.01	$	10.05	$	9.62
South Africa	$	2.74	$	1.37		$	1.69		$	1.81	$	2.20	$	1.58
Worldwide	$	9.99	$	8.78		$	9.50		$	9.58	$	9.74	$	9.19

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of ~~$33.3~~$35.9 million and $69.2 million during the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~$27.1~~$25.3 million and $52.4 million for the same ~~period~~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. ~~Consequently, during~~During the three and six months ended ~~March 31,~~June 30, 2011, the Company’s production and ad valorem taxes per BOE have, in the aggregate, increased 2028 percent and 24 percent, primarily reflecting increasing ~~oil~~commodity prices during the relevant ~~period.~~periods, partially offset by a decline in per-BOE ad valorem taxes.

The following table provides the Company’s production and ad valorem taxes per BOE from continuing operations for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010		2011		2010
Ad valorem taxes	$	1.44	$	1.48	$	1.35	$	1.58	$	1.39	$	1.53
Production taxes		1.88		1.28		1.97		1.01		1.93		1.14


Total ad valorem and production taxes	$	3.32	$	2.76	$	3.32	$	2.59	$	3.32	$	2.67

Depletion, depreciation and amortization expense. The Company’s total DD&A expense was ~~$140.4~~$153.9 million ($~~14.02~~14.26 per BOE) and $294.3 million ($14.15 per BOE) for the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~$144.4~~$144.3 million ($~~14.73~~14.71 per BOE) and $288.7 million ($14.72 per BOE) during the same ~~period~~respective periods of 2010. The decrease in DD&A expense per BOE during the three and six months ended ~~March 31,~~June 30, 2011, as compared to the same respective ~~period~~periods of 2010, is primarily due to a decrease in depletion expense per BOE on oil and gas properties.

Depletion expense on oil and gas properties was ~~$13.01~~$13.10 per BOE and $13.06 per BOE during the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~$14.02~~$13.89 per BOE and $13.95 per BOE during the same respective ~~period~~periods of 2010. The ~~seven~~six percent ~~decrease~~decreases in per-BOE depletion expense during the three and six months ended ~~March 31,~~June 30, 2011 isare primarily due to increases in proved reserves as a result of the Company’s successful drilling program and higher first-day-of-the-month commodity prices during the 12-month period ending on ~~the balance sheet date,~~June 30, 2011, which had the effect of extending the economic lives of proved properties.

The following table provides depletion expense per BOE from continuing operations by geographic area for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010		2011		2010
United States	$	12.13	$	12.51	$	12.33	$	12.65	$	12.23	$	12.58
South Africa	$	34.18	$	38.72	$	32.00	$	37.23	$	33.06	$	38.03
Worldwide	$	13.01	$	14.02	$	13.10	$	13.89	$	13.06	$	13.95

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

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

Exploration and abandonments expense. The following tables provide the Company’s geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense by geographic area for the three and six months ended ~~March 31,~~June 30, 2011 and 2010 (in thousands):


	United States			South Africa		Total			United States			South Africa		Total
Three Months Ended March 31, 2011
Three Months Ended June 30, 2011
Geological and geophysical	$	15,614		$	158	$	15,772		$	16,780		$	183	$	16,963
Exploratory dry holes		645			—		645			163			—		163
Leasehold abandonments and other		1,226			—		1,226			2,788			—		2,788

	$	17,485		$	158	$	17,643		$	19,731		$	183	$	19,914


Three Months Ended March 31, 2010
Three Months Ended June 30, 2010
Geological and geophysical	$	13,066		$	72	$	13,138		$	18,051		$	54	$	18,105
Exploratory dry holes		(109	)		—		(109	)		(125	)		—		(125	)
Leasehold abandonments and other		3,819			—		3,819			4,763			—		4,763

	$	16,776		$	72	$	16,848		$	22,689		$	54	$	22,743


									United States			South Africa		Total
Six Months Ended June 30, 2011
Geological and geophysical									$	32,393		$	341	$	32,734
Exploratory dry holes										808			—		808
Leasehold abandonments and other										4,015			—		4,015

									$	37,216		$	341	$	37,557


Six Months Ended June 30, 2010
Geological and geophysical									$	31,117		$	126	$	31,243
Exploratory dry holes										(234	)		—		(234	)
Leasehold abandonments and other										8,582			—		8,582

									$	39,465		$	126	$	39,591

The Company’s exploration and abandonment expense during the three and six months ended ~~March 31,~~June 30, 2011 is primarily comprised of acquisitions of 3-D seismic, geological and geophysical personnel costs and unproved property abandonments in the United States.

During the ~~three~~six months ended ~~March 31,~~June 30, 2011, the Company drilled and evaluated 1764 exploration/extension wells, all of which were successfully completed as discoveries. During the same period in 2010, the Company drilled and evaluated ~~three~~11 exploration/extension wells, all of which were successfully completed as discoveries.

General and administrative expense.General and administrative expense for the three and six months ended ~~March 31,~~June 30, 2011 was ~~$44.1~~$44.6 million and $88.8 million, respectively, as compared to ~~$38.3~~$40.4 million and $78.7 million during the same ~~period~~respective periods of 2010. The increase in general and administrative expense for the three and six months ended ~~March 31,~~June 30, 2011, as compared to the same ~~period~~periods of 2010, was primarily due to an increase in ~~performance-related~~ compensation expense related to hiring activities since June 30, 2010 in support of the Company’s capital expansion initiatives and vertical integration efforts, partially offset by an increase in producing, drilling, and other overhead recoveries. The increase in compensation expense in the quarter-to-quarter comparison is largely due to a 39 percent increase in total employees since March 31, 2010, in support of the Company’s expansion initiatives and vertical integration efforts. In support of these strategic growth initiatives, the Company anticipates continued growth in total employees and compensation-related expenses.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.7 million and $5.3 million for the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~$2.9~~$2.5 million and $5.4 million during the same ~~period~~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 ~~$45.2~~$45.8 million and $91.0 million for the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~$47.5~~$45.4 million and $92.9 million during the same ~~period~~respective periods of 2010. The ~~$2.3~~$1.9 million decrease in interest expense during the ~~three~~six months ended ~~March 31,~~June 30, 2011, as

compared to the same period of 2010, is primarily due to a decrease in credit facility borrowings, partially offset by ~~the~~an increase in the weighted average interest rate. The weighted average interest rate on the Company’s indebtedness for both the three and six months ended ~~March 31,~~June 30, 2011, including the effects of ~~interest rate derivatives and~~ capitalized interest, was ~~7.2~~7.3 percent, as compared to ~~6.8~~7.0 percent and 6.9 percent for the same ~~period~~respective periods of 2010.

Derivative (gains) losses, net.During the three months ended ~~March 31,~~June 30, 2011, the Company recorded ~~$244.4~~$229.5 million of net derivative gains on commodity price and interest rate derivatives. For the three months ended June 30, 2011, $221.2 million represented unrealized gains and $8.3 million represented realized gains. During the six months ended June 30, 2011, the Company recorded $15.0 million of net derivative losses on commodity price and interest rate derivatives. For the ~~three~~six months ended ~~March 31,~~June 30, 2011, ~~$275.8~~$54.6 million represented unrealized losses ~~subject to continuing market risk~~ and ~~$31.4~~$39.6 million represented realized gains. During the three and six months ended ~~March 31,~~June 30, 2010, the Company recorded ~~$265.5~~$177.5 million and $443.0 million of net derivative gains. Derivative gains and losses result from changes in the fair values of the Company’s derivative contracts. See Notes D and G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the Company’s derivative activities and market risks associated with those activities.

Hurricane activity, net.The Company recorded net hurricane related charges of $71 thousand during the three months ended March 31, 2011, as compared to net hurricane related recoveries of $7.4 million during the same period of 2010. Hurricane activity is associated with the Company’s East Cameron platform facility, located on the Gulf of Mexico shelf, which was destroyed during 2005 by Hurricane Rita. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and are substantially complete. The Company estimates that it will expend approximately $2.5 million during 2011 to complete the operations to reclaim and abandon the East Cameron 322 facility, which has been fully accrued as an asset retirement obligation in the accompanying consolidated balance sheets.

Other expense.Other expense for the three and six months ended ~~March 31,~~June 30, 2011 was ~~$17.9~~$14.4 million and $32.3 million, respectively, as compared to ~~$15.9~~$14.2 million and $30.1 million for the same ~~period~~respective periods of 2010. The ~~$2.0 million~~ increase in other expense for the three months ended ~~March 31,~~June 30, 2011, as compared to the same period in 2010, is primarily attributable to a ~~$5.3~~$5.7 million increase in unused gas transportation costs, partially offset by a $4.9 million decrease in charges recorded for the difference between Pioneer contracted rig rates and market rig rates that are charged to joint operations. The increase in other expense for the six months ended June 30, 2011, as compared to the same period in 2010, is primarily attributable to a $11.0 million increase in unused gas transportation costs and a $2.4 million charge associated with renewing the Company’s credit facility, partially offset by a ~~$5.1~~$10.0 million decrease in ~~excess and terminated~~above market drilling rig related costs. See Note P of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information.

Income tax ~~(provision) benefit.~~provision.The Company ~~recognized an~~recorded income tax ~~benefit~~provisions from continuing operations of ~~$47.2~~$144.7 million and $97.5 million during the three and six months ended ~~March 31,~~June 30, 2011, respectively, as compared to ~~an income tax provision of $144.0~~$83.2 million and $227.2 million during the same respective ~~period~~periods of 2010. The ~~change~~changes in the income tax ~~(provision) benefit~~provisions for the three and six months ended ~~March 31,~~June 30, 2011, as compared to the same ~~period~~periods of 2010, isare primarily due to noncash derivative gains and losses associated with mark-to-market accounting. The Company’s effective tax rate of 4237 percent and 35 percent during the three and six months ended ~~March 31,~~June 30, 2011, excluding net income attributable to noncontrolling interests, ~~differs from~~are consistent with the Company’s combined United States federal and state statutory rate of approximately 37 ~~percent primarily due to tax provisions on foreign repatriated earnings and adjustments to state deferred tax liabilities.~~percent.

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

Income (loss) from discontinued operations, net of tax.The Company reported a loss from discontinued operations, net of tax of $1.6 million and income from discontinued operations, net of tax of ~~$414.6~~$413.1 million for the three and six months ended June 30, 2011, respectively, as compared to income from discontinued operations, net of tax of $41.9 million and $45.7 million for the same respective periods of 2010.

During February 2011, the Company completed the sale of 100 percent of the Company’s share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $853.7 million, including normal post-closing adjustments, resulting in a pretax gain of $645.3 million. During the three months ended June 30, 2011, post-closing adjustments reduced the net gain on the transaction by $4.6 million.

The loss from discontinued operations for the three months ended ~~March 31,~~June 30, 2011 ~~as compared to $3.8 million for the same period of 2010. The increase in income from discontinued operations~~ is primarily ~~attributable~~comprised of the after tax impact of the aforementioned adjustment to ~~the $649.9 million pretax~~net gain ~~recorded~~ on the sale of Pioneer ~~Tunisia, partially offset by related income taxes.~~Tunisia. Discontinued operations for the three and six months ended June 30, 2010 include the historical results of operations of Pioneer Tunisia. See Note Q of the Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s discontinued operations.

Net income attributable to noncontrolling interest. Net ~~loss~~income attributable to the noncontrolling interests for the three and six months ended ~~March 31,~~June 30, 2011 was ~~$4.8~~$20.1 million and $15.3 million, respectively, as compared to net income attributable to the noncontrolling interests of ~~$15.4~~$21.1 million and $36.5 million for the same respective ~~period~~periods of 2010. The ~~$20.2~~$1.0 million ~~decrease~~and $21.2 million decreases in net income attributable to noncontrolling interests for the three and six months ended ~~March 31,~~June 30, 2011, as compared to the same ~~period~~respective periods in 2010, isare primarily due to ~~a decrease in Pioneer Southwest’s net income that resulted from an increase~~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.The Company’s primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payment of contractual obligations, including EFS Midstream capital funding commitments, dividends/distributions and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or external financing sources as discussed in “Capital resources” below. The Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internally-generated cash flows, cash on hand and with its liquidity under its credit facility, although no assurances can be given that such funding sources will be adequate to meet the Company’s future needs.

The Company generally strives to limit its capital expenditures to a level that allows the Company to deliver net cash flow from operating activities in excess of capital requirements in order to enhance and preserve financial flexibility. However, during 2011, the Company will redeploy a portion of the proceeds from the sale of Pioneer Tunisia to accelerate drilling in the Eagle Ford Shale, Spraberry and Barnett Shale Combo areas. During 2011, the Company’s capital budget will continue to focus on oil- and liquid-rich-gas drilling activities with total expenditures forecasted to be ~~$1.8~~$2.1 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream investments), consisting of ~~$1.6~~$1.8 billion for drilling operations and ~~$200~~$300 million for vertical integration and facilities. Based on results for the first ~~quarter results~~half of 2011 and ~~current~~the forecasted production volumes and NYMEX commodity prices for the second half of 2011, the Company expects its cash flows from operating activities plus a portion of the proceeds from the sale of Pioneer Tunisia to be sufficient to fund its planned capital expenditures and contractual obligations. During the first ~~three~~six months of 2011, the Company’s ~~capital~~ costs incurred (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream investments) were ~~$434.2~~$801.8 million, as compared to ~~$189.0~~$399.0 million during the first ~~three~~six months of 2010. In addition, during the first six months of 2011, the Company paid $215.4 million for additions to other assets and other property and equipment, net, which includes amounts associated with vertical integration and facilities, as compared to $74.1 million during the fisrt six months of 2010.

Investing activities. Investing activities ~~provided $334.2~~used $241.9 million of cash during the ~~three~~six months ended ~~March 31,~~June 30, 2011, as compared to ~~$166.5~~$238.4 million used during the ~~three~~six months ended ~~March 31,~~June 30, 2010. The ~~$500.7~~$3.5 million increase in net cash ~~provided~~used by investing activities for the ~~three~~six months ending ~~March 31,~~June 30, 2011, as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2010, is primarily due to a ~~$775.5~~$516.2 million increase in proceeds from disposition of assets due to the sale of Pioneer Tunisia, ~~partially~~substantially offset by a ~~$153.4~~$295.6 million increase in additions to oil and gas properties due to the Company’s increased drilling activities in 2011, ~~an $84.3~~a $141.3 million increase in additions to other assets and other property and equipment, primarily comprising purchases of drilling rigs, fracture stimulation equipment and well servicing

equipment, and ~~a $37.0~~an $82.7 million increase in investments in unconsolidated affiliates. During the ~~three~~six months ended ~~March 31,~~June 30, 2011, ~~and 2010,~~ the Company’s expenditures for additions to oil and gas properties were funded by net cash provided by operating activities and a portion of the proceeds from the sale of Pioneer Tunisia. During the same period in 2010, the Company’s expenditures for additions to oil and gas properties were funded by net cash provided by operating activities.

Dividends/distributions. During February of both 2011 and 2010, the Company’s board of directors (“the Board”) declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $4.8 million of aggregate dividends during each of the six months ended June 30, 2011 and 2010. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company’s liquidity and capital resources at the time.

During January ~~of both~~ 2011 and ~~2010,~~April 2011, the Pioneer Southwest board of directors (the “Pioneer Southwest Board”) declared quarterly distributions of $0.50 and $0.51 per limited partner ~~unit.~~unit, respectively, compared to the $0.50 per limited partner unit quarterly distribution declared in January and April 2010. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of ~~$6.3~~$12.7 million and $12.6 million during ~~February~~the six months ended June 30, 2011 and 2010, respectively. ~~In addition, during April~~During July 2011, the Pioneer Southwest Board declared a quarterly distribution of $0.51 per limited partner unit ~~representing a $.01 per unit, or two percent, increase in quarterly distributions. The distribution is payable on May 12, 2011 to~~for unitholders of record on ~~May 2,~~August 1, 2011, payable August 11, 2011. Future distributions are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the current distribution amount based on Pioneer Southwest’s liquidity and capital resources at the time.

Contractual obligations, including off-balance sheet obligations. The Company’s contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, other liabilities, transportation commitments, VPP obligations and ~~midstream~~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 ~~to EFS Midstream, for gathering, treating and transportation services over a 20-year contractual term,~~ 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 ~~March 31,~~June 30, 2011, the material off-balance sheet arrangements and transactions that the Company has entered into included (i) undrawn letters of credit, (ii) operating lease agreements, (iii) ~~drilling and~~ transportation commitments, (iv) open purchase commitments (v) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future), and (vi) ~~EFS Midstream capital funding~~

~~commitments 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 and gathering, treating and transportation commitments on uncertain volumes~~rates. During June 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility to fund infrastructure investments that are in excess of ~~future throughput.~~operating cash flow. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. Since December 31, 2010, the material changes in the Company’s contractual obligations include (i) a ~~$39.0~~$30.7 million decrease in outstanding long-term debt, (ii) ~~an $11.1~~a $22.3 million decrease in the Company’s VPP obligations and (iii) a ~~$216.0~~$46.5 million increase in the Company’s derivative liabilities.

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

The Company’s commodity and interest rate derivative contracts that are periodically measured and recorded at fair value represent those derivatives that continue to be subject to market or credit risk. As of ~~March 31,~~June 30, 2011, these contracts represented net ~~liabilities~~assets of ~~$99.7~~$112.4 million. The ultimate liquidation value of the Company’s commodity and interest rate derivatives that are subject to market risk will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives’ fair values as of ~~March 31,~~June 30, 2011. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information about the Company’s derivative instruments and market risk.

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 ~~three~~six months ended ~~March 31,~~June 30, 2011 was ~~$143.2~~$564.5 million as compared to ~~$299.4~~$693.2 million during the same period of 2010. The decrease in net cash provided by operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2011, as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2010, is primarily due to ~~working capital changes,~~the 2010 recovery of $119.3 million of excess royalty payments associated with properties that were sold by the Company during 2006, plus $35.3 million of associated interest, and operating cash flow from Pioneer Tunisia during 2010, partially offset by an increase in ~~commodity sales.~~oil and NGL production and prices.

Asset divestitures.During February 2011, the Company completed the sale ~~to an unaffiliated third party~~ of 100 percent of the Company’s share holdings in Pioneer Tunisia to an unaffiliated third party for net cash proceeds of ~~$845.2~~$853.7 million, including normal post-closing adjustments, ~~receivable,~~ resulting in a pretax gain of ~~$649.9~~$645.3 million. The net cash proceeds from the sale of Pioneer Tunisia were determined in accordance with the sale and purchase agreement that the Company entered into with the purchaser, which ~~provides~~provided for certain customary adjustments for matters occurring after the effective date of the sale, such as capital contributions and distributions, and working capital adjustments. Adjustments to net cash proceeds involve management’s best estimate about the realizable value of working capital items, including that the amounts are reasonably assured of collection. Differences between actual working capital amounts and management’s estimates recorded as of ~~March 31,~~June 30, 2011, if any, will be recorded as income or loss from discontinued operations in future periods. See Note Q of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for information regarding the Company’s discontinued operations.

During the first six months of 2010, the ~~Company sold~~Company’s asset divestitures included the completion of the Eagle Ford Shale joint venture transactions for net proceeds of $272.0 million, the sale of certain Uinta/Piceance proved and unproved oil and gas properties ~~in the Uinta/Piceance area~~ for $11.8 million of net proceeds ~~of $11.8 million~~ and the ~~assumption~~collection of certain ~~asset retirement obligations, resulting in a pretax gain of $17.3 million.~~Tunisia past cost receivables. See Note N of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for information regarding the Company’s divestitures.

Financing activities. Net cash used in financing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2011 and 2010 was ~~$67.9~~$81.3 million and ~~$125.6~~$284.5 million, respectively. The ~~$57.7~~$203.2 million decrease in cash used in financing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2011, as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2010, is primarily due to (i) a ~~$73.9~~$197.9 million decline in net payments on long-term debt and (ii) a ~~$21.4~~$23.8 million increase in excess tax benefits from share-based payment arrangements, partially offset by (iii) a ~~$22.7~~$25.8 million increase in ~~the costs of~~ treasury shares purchased to satisfy withholding tax payments onrelated to the vesting of employee share-based ~~payment lapses and (iv) $8.7 million of 2011 payments of financing fees to replace the Company’s Credit Facility.~~awards.

During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”) with a syndicate of financial institutions that matures in March 2016, unless extended in accordance with the terms of the Credit Facility. The Credit Facility replaces the Company’s Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 (the “expired Credit Facility”) and provides for aggregate loan commitments of $1.25 billion. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for information about the available loans, interest rates and debt covenant terms of the Credit Facility.

~~Effective April 1,~~The Company’s stock price during March 2011 caused the Company’s 2.875% Convertible Senior Notes ~~became~~to be convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, holders of 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During July and August 2011, the Company paid the holders a total of $71 thousand of cash and issued 340 shares of the Company’s common stock. During June 2011, the Company’s stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders for the ~~quarter~~three months ended ~~June~~September 30, ~~2011, and~~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 the 2.875% Convertible Senior Notes had qualified for and been converted as of March 31, 2011, the note holders would have received $480.0 million of cash and approximately 2.9 million shares of the Company’s common stock, which was valued at $295.4 million at March 31, 2011. The Company intends to fund the cash portion of future conversion payments, if any, with cash on hand and borrowings under the Credit Facility. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for more information about the Company’s 2.875% Convertible Senior Notes.

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 ~~March 31,~~June 30, 2011, the Company had no outstanding borrowings under its Credit Facility and was in compliance with all of its debt covenants. After adjusting for $65.1 million of undrawn and outstanding letters of credit under its Credit Facility, the Company had approximately $1.2 billion of unused borrowing capacity as of ~~March 31,~~June 30, 2011. If internal cash flows and cash on hand do not meet the Company’s expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its Credit Facility, issuances of debt or equity securities or from other sources, such as asset sales. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal operating cash flows, cash on hand and borrowing capacity under the Company’s Credit Facility will be adequate to fund 2011 capital expenditures and dividend/distribution payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company’s future needs. For instance, the amount that the Company may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.

Debt ratings. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies ~~consider~~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 ~~March 31,~~June 30, 2011 was ~~$6.6~~$7 billion, consisting of ~~$520.7~~$352.4 million of cash and cash equivalents, debt of $2.6 billion and stockholders’ equity of ~~$4.6~~$4.8 billion. The Company’s net debt to net book capitalization was 3132 percent and 37 percent at ~~March 31,~~June 30, 2011 and December 31, 2010, respectively. The Company’s ratio of current assets to current liabilities was ~~1.78~~1.42 to 1.00 at ~~March 31,~~June 30, 2011 as compared to 1.56 to 1.00 at December 31, 2010.

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

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010. As such, the information contained herein should be read in conjunction with the related disclosures in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s potential exposure to market risks. The term “market risks,” insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices, foreign exchange rates and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. All of the Company’s market risk sensitive instruments are entered into for purposes other than ~~speculative.~~speculation.

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


	Derivative Contract Net Assets (Liabilities)									Derivative Contract Net Assets
	Commodities			Interest Rates			Total			Commodities			Interest Rates			Total
	(in thousands)									(in thousands)
Fair value of contracts outstanding as of December 31, 2010	$	167,567		$	17,552		$	185,119		$	167,567		$	17,552		$	185,119
Changes in contract fair value (a)		(242,280	)		(2,152	)		(244,432	)		(27,377	)		12,423			(14,954	)
Contract maturities		(35,347	)		(5,029	)		(40,376	)		(52,729	)		(5,029	)		(57,758	)

Fair value of contracts outstanding as of March 31, 2011	$	(110,060	)	$	10,371		$	(99,689	)
Fair value of contracts outstanding as of June 30, 2011										$	87,461		$	24,946		$	112,407

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.

The following table provides information about financial instruments to which the Company was a party as of ~~March 31,~~June 30, 2011 and that are sensitive to changes in interest rates. For debt obligations, the table presents maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt’s estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of ~~March 31,~~June 30, 2011. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on ~~May~~August 2, 2011.


	Nine Months Ending December 31, 2011																										Asset (Liability) Fair Value at March 31, 2011
				Year Ending December 31,																										Six Months Ending December 31, 2011				Year Ending December 31,																		Asset (Liability) Fair Value at June 30, 2011
				2012				2013				2014				2015				Thereafter				Total						Six Months Ending December 31, 2011			2012				2013			2014			2015			Thereafter			Total			Asset (Liability) Fair Value at June 30, 2011
		($ in thousands)																														($ in thousands)

Total Debt:
Fixed rate principal maturities (a)	$	—			$	—			$	480,000			$	—			$	—			$	2,089,985			$	2,569,985	$	(3,099,760	)		$	—			$	—		$	480,000		$	—		$	—		$	2,089,985		$	2,569,985		$	(3,013,767	)
Weighted average interest rate		6.05	%			6.05	%			6.72	%			6.78	%			6.78	%			7.13	%									6.05	%			6.05	%		6.73	%		6.78	%		6.78	%		7.13	%
Variable rate principal maturities:
Pioneer Southwest credit facility	$	—			$	—			$	85,000			$	—				—				—			$	85,000	$	(81,289	)		$	—			$	—		$	87,000		$	—		$	—		$	—		$	87,000		$	(84,542	)
Weighted average interest rate		1.24	%			1.90	%			3.02	%																					1.34	%			1.48	%		1.71	%		—			—			—
Interest Rate Swaps:
Credit facility:
Notional debt amount (b)	$	470,000			$	470,000			$	470,000			$	470,000			$	470,000			$	470,000					$	10,371
Interest Rate Swaps (b):
Notional debt amount (c)																															$	470,000			$	470,000		$	470,000		$	470,000		$	470,000		$	470,000					$	24,946
Fixed rate receivable (%)		2.92	%			2.92	%			2.92	%			2.92	%			2.92	%			3.09	%									2.92	%			2.92	%		2.92	%		2.92	%		2.92	%		3.09	%
Variable rate payable (%)		0.36	%			1.02	%			2.15	%			3.03	%			3.42	%			3.42	%									0.46	%			0.60	%		0.83	%		1.89	%		2.40	%		2.54	%

Commodity derivative instruments and price sensitivity.The following table provides information about the Company’s oil, NGL, gas and ~~gas~~diesel derivative financial instruments that were sensitive to changes in oil, NGL, gas and ~~gas~~diesel fuel prices as of ~~March 31,~~June 30, 2011. Although mitigated by the Company’s derivative activities, declines in ~~commodity~~oil, NGL and gas prices would reduce the Company’s revenues and ~~internally-generated cash flows.~~increases in diesel prices would increase the Company’s internally-provided workover, capital and related services costs.

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

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

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 ~~March 31,~~June 30, 2011 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

The Company is party to the legal proceeding ~~that is~~ described ~~under “Legal actions”~~ in Note J of Notes to Consolidated Financial Statements included in ~~“Item~~“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.

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. ~~There~~Except as set forth below, there has been no material change in the Company’s risk factors from those described in the Annual Report on Form 10-K.

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

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

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

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

These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may materially adversely affect the Company’s business, financial condition or future results.

The following table summarizes the Company’s purchases of treasury stock during the three months ended ~~March 31,~~June 30, 2011:

~~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.~~

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.


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)


		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 ~~March 31,~~June 30, 2011 and December 31, 2010		5

	Consolidated Statements of Operations for the three and six months ended ~~March 31,~~June 30, 2011 and 2010		7

	Consolidated Statement of Stockholders’ Equity for the ~~three~~six months ended ~~March 31,~~June 30, 2011		8

	Consolidated Statements of Cash Flows for the ~~three~~six months ended ~~March 31,~~June 30, 2011 and 2010		9

	Consolidated Statements of Comprehensive Income for the three and six months ended ~~March 31,~~June 30, 2011 and 2010		10

	Notes to Consolidated Financial Statements		11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		3234

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		4448

Item 4.	Controls and Procedures		4751

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		4852

Item 1A.	Risk Factors		4852

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		4853

Item 6.	Exhibits		4954

Signatures			5055

Exhibit Index			5156


	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)

Income (loss) as reported	$	267,284		$	(1,584	)	$	265,700		$	196,446		$	413,058		$	609,504
Net income attributable to the noncontrolling interests		(20,123	)		—			(20,123	)		(15,333	)		—			(15,333	)
Participating basic earnings		(4,847	)		—			(4,847	)		(3,307	)		(7,542	)		(10,849	)

Basic net income (loss) attributable to common stockholders		242,314			(1,584	)		240,730			177,806			405,516			583,322
Reallocation of participating earnings		164			—			164			82			189			271

Diluted income (loss) attributable to common stockholders	$	242,478		$	(1,584	)	$	240,894		$	177,888		$	405,705		$	583,593


	Three Months Ended June 30, 2010									Six Months Ended June 30, 2010
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)

Income as reported	$	146,838		$	41,851		$	188,689		$	403,633		$	45,662		$	449,295
Net income attributable to the noncontrolling interests		(21,113	)		—			(21,113	)		(36,465	)		—			(36,465	)
Participating basic earnings		(3,063	)		(1,020	)		(4,083	)		(8,351	)		(1,039	)		(9,390	)

Basic income attributable to common stockholders		122,662			40,831			163,493			358,817			44,623			403,440
Reallocation of participating earnings		84			28			112			98			12			110

Diluted income attributable to common stockholders	$	122,746		$	40,859		$	163,605		$	358,915		$	44,635		$	403,550


Number of shares of Common Stock outstanding as of ~~May 2,~~August 1, 2011		~~116,755,591~~ 116,782,548


	Development Drilling
	Beginning Wells in Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells in Progress
United States		23		143		139		—		27


	Exploration/Extension Drilling
	Beginning Wells in Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells in Progress
United States		38		36		17		—		57


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)
January 2011		160,068	$	86.82		—
February 2011		128,917	$	96.66		—
March 2011		98,012	$	95.13		—

Total		386,997	$	92.20		—	$	355,789,018


Exhibit Number		Description
~~10.1~~	—	Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 5, 2011).

~~12.1(a)~~	—	~~Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.~~

~~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(b)~~	—	~~XBRL Instance Document.~~

~~101.SCH(b)~~	—	~~XBRL Taxonomy Extension Schema.~~

~~101.CAL(b)~~	—	~~XBRL Taxonomy Extension Calculation Linkbase Document.~~

~~101.DEF(b)~~	—	~~XBRL Taxonomy Extension Definition Linkbase Document.~~

~~101.LAB(b)~~	—	~~XBRL Taxonomy Extension Label Linkbase Document.~~

~~101.PRE(b)~~	—	~~XBRL Taxonomy Extension Presentation Linkbase Document.~~


	~~PIONEER NATURAL RESOURCES COMPANY~~

~~Date: May 9, 2010~~	~~By:~~	~~/s/ Richard P. Dealy~~
		~~Richard P. Dealy~~
		~~Executive Vice President and Chief~~
		~~Financial Officer~~

~~Date: May 9, 2010~~	~~By:~~	~~/s/ Frank W. Hall~~
		~~Frank W. Hall~~
		~~Vice President and Chief~~
		~~Accounting Officer~~


~~Exhibit~~ ~~Number~~		~~Description~~
~~10.1~~	—	Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 5, 2011).

~~12.1(a)~~	—	~~Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.~~

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(b)~~101.INS(a)	—	XBRL Instance Document.

~~101.SCH(b)~~101.SCH(a)	—	XBRL Taxonomy Extension Schema.

~~101.CAL(b)~~101.CAL(a)	—	XBRL Taxonomy Extension Calculation Linkbase Document.

~~101.DEF(b)~~101.DEF(a)	—	XBRL Taxonomy Extension Definition Linkbase Document.

~~101.LAB(b)~~101.LAB(a)	—	XBRL Taxonomy Extension Label Linkbase Document.

~~101.PRE(b)~~101.PRE(a)	—	XBRL Taxonomy Extension Presentation Linkbase Document.


	PIONEER NATURAL RESOURCES COMPANY

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

Date: August 5, 2011	By:	/s/ Frank W. Hall
		Frank W. Hall
		Vice President and Chief
		Accounting Officer

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company