Pioneer Natural Resources (PXD) 10-Q/A 12 Aug 09 2009 Q2 Quarterly report (amended) Financial data

Statement Of Financial Position

Statement Of Financial Position Classified (USD $)
In Thousands	Jun. 30, 2009	Dec. 31, 2008
Current assets:
Cash and cash equivalents	$64,323	$48,337	[1]
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,472 and $22,464 as of June 30, 2009 and December 31, 2008, respectively	152,231	206,794	[1]
Due from affiliates	700	759	[1]
Income taxes receivable	28,777	60,573	[1]
Inventories	119,077	76,901	[1]
Prepaid expenses	19,870	12,464	[1]
Deferred income taxes	9,239	6,510	[1]
Discontinued operations held for sale	16,874	0	[1]
Other current assets:
Derivatives	63,830	59,622	[1]
Other, net of allowance for doubtful accounts of $5,566 and $5,491 as of June 30, 2009 and December 31, 2008, respectively	6,929	14,951	[1]
Total current assets	481,850	486,911	[1]
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	10,105,381	10,167,220	[1]
Unproved properties	197,986	204,183	[1]
Accumulated depletion, depreciation and amortization	(2,671,508)	(2,511,401)	[1]
Total property, plant and equipment	7,631,859	7,860,002	[1]
Deferred income taxes	1,134	553	[1]
Goodwill	310,551	310,563	[1]
Other property and equipment, net	158,775	161,266	[1]
Other assets:
Derivatives	40,337	72,594	[1]
Other, net of allowance for doubtful accounts of $5,167 and $4,410 as of June 30, 2009 and December 31, 2008, respectively	248,336	269,896	[1]
Assets, Total	8,872,842	9,161,785	[1]
Accounts payable:
Trade	192,542	322,688	[1]
Due to affiliates	13,262	34,284	[1]
Interest payable	43,348	43,247	[1]
Income taxes payable	17,713	3,618	[1]
Deferred income taxes	370	0	[1]
Discontinued operations held for sale	16,706	0	[1]
Other current liabilities:
Derivatives	108,360	49,561	[1]
Deferred revenue	119,281	147,905	[1]
Other	68,177	93,694	[1]
Total current liabilities	579,759	694,997	[1]
Long-term debt	2,978,819	2,899,241	[1]
Derivatives	47,645	20,584	[1]
Deferred income taxes	1,424,769	1,501,459	[1]
Deferred revenue	132,166	177,236	[1]
Other liabilities	168,598	187,409	[1]
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 125,135,994 and 124,566,963 shares issued at June 30, 2009 and December 31, 2008, respectively	1,251	1,246	[1]
Additional paid-in capital	2,924,939	2,909,735	[1]
Treasury stock, at cost: 11,113,561 and 10,020,502 shares at June 30, 2009 and December 31, 2008, respectively	(426,598)	(411,659)	[1]
Retained earnings	875,226	988,786	[1]
Accumulated other comprehensive income - deferred hedge gains, net of tax	76,637	88,788	[1]
Total stockholders' equity attributable to common stockholders	3,451,455	3,576,896	[1]
Noncontrolling interest in consolidating subsidiaries	89,631	103,963	[1]
Total stockholders' equity	3,541,086	3,680,859	[1]
Commitments and contingencies	0	0	[1]
Liabilities and Stockholders' Equity, Total	$8,872,842	$9,161,785	[1]
[1]Retrospectively adjusted as described in Note B.

1_Statement Of Financial Positi

Statement Of Financial Position Classified (Parenthetical) (USD $)
In Thousands, except Share data	Jun. 30, 2009	Dec. 31, 2008
Trade, allowance for doubtful accounts	$1,472	$22,464	[1]
Other, allowance for doubtful accounts	5,566	5,491	[1]
Other, allowance for doubtful accounts	$5,167	$4,410	[1]
Common stock, par value	0.01	0.01	[1]
Common stock, shares authorized	500,000,000	500,000,000	[1]
Common stock, shares issued	125,135,994	124,566,963	[1]
Treasury stock, shares	11,113,561	10,020,502	[1]
[1]Retrospectively adjusted as described in Note B.

Statement Of Income Alternative

Statement Of Income Alternative (USD $)
In Thousands, except Per Share data	3 Months Ended Jun. 30, 2009	3 Months Ended Jun. 30, 2008		6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 30, 2008
Revenues and other income:
Oil and gas	$370,692	$635,123	[1]	$738,543	$1,177,166	[1]
Derivative gains, net	0	881	[1]	0	1,908	[1]
Interest and other	88,598	6,887	[1]	99,258	31,911	[1]
Gain (loss) on disposition of assets, net	53	3,901	[1]	(62)	4,578	[1]
Total revenues and other income, Total	459,343	646,792	[1]	837,739	1,215,563	[1]
Costs and expenses:
Oil and gas production	84,793	97,327	[1]	195,223	190,140	[1]
Production and ad valorem taxes	23,715	45,658	[1]	51,414	83,546	[1]
Depletion, depreciation and amortization	165,943	112,251	[1]	354,087	216,888	[1]
Impairment of oil and gas properties	0	0	[1]	21,091	0	[1]
Exploration and abandonments	21,618	26,108	[1]	52,788	63,293	[1]
General and administrative	33,275	35,596	[1]	67,929	72,117	[1]
Accretion of discount on asset retirement obligations	2,753	1,961	[1]	5,505	3,904	[1]
Interest	43,475	41,670	[1]	84,613	81,948	[1]
Hurricane activity, net	16,075	1,401	[1]	16,450	1,859	[1]
Derivative losses, net	170,224	0	[1]	70,361	0	[1]
Other	36,715	8,275	[1]	68,104	20,190	[1]
Costs and Expenses, Total	598,586	370,247	[1]	987,565	733,885	[1]
Income (loss) from continuing operations before income taxes	(139,243)	276,545	[1]	(149,826)	481,678	[1]
Income tax benefit (provision)	44,398	(120,975)	[1]	45,139	(204,451)	[1]
Income (loss) from continuing operations	(94,845)	155,570	[1]	(104,687)	277,227	[1]
Income from discontinued operations, net of tax	2,731	7,351	[1]	1,761	14,391	[1]
Net income (loss)	(92,114)	162,921	[1]	(102,926)	291,618	[1]
Net (income) loss attributable to the noncontrolling interest	522	(6,227)	[1]	(3,271)	(6,965)	[1]
Net income (loss) attributable to common stockholders	(91,592)	156,694	[1]	(106,197)	284,653	[1]
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	-0.82	1.24	[1]	-0.95	2.26	[1]
Income from discontinued operations, net of tax, attributable to common stockholders	0.02	0.06	[1]	0.02	0.12	[1]
Net income (loss) attributable to common stockholders	-0.8	1.3	[1]	-0.93	2.38	[1]
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	-0.82	1.23	[1]	-0.95	2.25	[1]
Income from discontinued operations, net of tax, attributable to common stockholders	0.02	0.06	[1]	0.02	0.12	[1]
Net income (loss) attributable to common stockholders	-0.8	1.29	[1]	-0.93	2.37	[1]
Weighted average shares outstanding:
Basic	113,979	118,363	[1]	114,116	118,149	[1]
Diluted	113,979	119,370	[1]	114,116	118,816	[1]
Dividends declared per share	$0	$0	[1]	0.04	0.14	[1]
Amounts attributable to common stockholders:
Income (loss) from continuing operations	(94,323)	149,343	[1]	(107,958)	270,262	[1]
Discontinued operations, net of tax	2,731	7,351	[1]	1,761	14,391	[1]
Net income (loss)	($91,592)	$156,694	[1]	($106,197)	$284,653	[1]
[1]Retrospectively adjusted as described in Note B.

Statement Of Shareholders Equit

Statement Of Shareholders Equity And Other Comprehensive Income (USD $)
In Thousands			Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Income [Member]		Noncontrolling Interest		Total
Beginning Balance at Dec. 31, 2008			$1,246	[1]	$2,909,735	[1]	($411,659)	[1]	$988,786	[1]	$88,788	[1]	$103,963	[1]	$3,680,859	[1]
Beginning Balance at Dec. 31, 2008	114,546	[1]
Dividends declared ($0.04 per share)									(4,696)						(4,696)
Exercise of long-term incentive plan stock options	132
Exercise of long-term incentive plan stock options							5,202		(2,667)						2,535
Purchase of treasury stock	(1,225)
Purchase of treasury stock							(20,141)						(258)		(20,399)
Tax benefits related to stock-based compensation					(3,918)										(3,918)
Compensation costs:
Vested compensation awards, net	569
Vested compensation awards, net			5		(5)										0
Compensation costs included in net income					19,127								96		19,223
Cash contributions of noncontrolling interest partners													150		150
Cash distributions to noncontrolling interest partners													(10,050)		(10,050)
Net income (loss)									(106,197)				3,271		(102,926)
Deferred hedging activity, net of tax:
Hedge fair value changes, net											10,477		3,692		14,169
Net hedge (gains) losses included in continuing operations											(22,628)		(11,233)		(33,861)
Ending Balance at Jun. 30, 2009	114,022
Ending Balance at Jun. 30, 2009			$1,251		$2,924,939		($426,598)		$875,226		$76,637		$89,631		$3,541,086
[1]Retrospectively adjusted as described in Note B.

2_Statement Of Shareholders Equ

Statement Of Shareholders Equity And Other Comprehensive Income (Parenthetical) (USD $)
	Retained Earnings	Total
Dividends declared, per share	0.04	0.04

Statement Of Cash Flows Indirec

Statement Of Cash Flows Indirect (USD $)
In Thousands	3 Months Ended Jun. 30, 2009	3 Months Ended Jun. 30, 2008		6 Months Ended Jun. 30, 2009		6 Months Ended Jun. 30, 2008
Cash flows from operating activities:
Net income (loss)	($92,114)	$162,921	[1]	($102,926)		$291,618	[1]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	165,943	112,251	[1]	354,087		216,888	[1]
Impairment of oil and gas properties	0	0	[1]	21,091		0	[1]
Exploration expenses, including dry holes	9,705	1,034	[1]	27,954		4,582	[1]
Hurricane activity, net	15,000	0	[1]	15,000		0	[1]
Deferred income taxes	(41,761)	108,937	[1]	(52,793)		171,310	[1]
(Gain) loss on disposition of assets, net	(53)	(3,901)	[1]	62		(4,578)	[1]
Accretion of discount on asset retirement obligations	2,753	1,961	[1]	5,505		3,904	[1]
Discontinued operations	312	6,181	[1]	5,208		14,464	[1]
Interest expense	6,921	7,797	[1]	13,529		14,094	[1]
Derivative related activity	159,520	7,851	[1]	48,235		15,516	[1]
Amortization of stock-based compensation	9,926	8,268	[1]	19,223		17,248	[1]
Amortization of deferred revenue	(36,975)	(39,457)	[1]	(73,695)		(78,936)	[1]
Other noncash items	14,146	8,427	[1]	24,840		3,788	[1]
Change in operating assets and liabilities
Accounts receivable, net	11,720	(84,474)	[1]	53,941		(98,535)	[1]
Income taxes receivable	(13,140)	(9,326)	[1]	31,796		(9,402)	[1]
Inventories	(23,219)	(14,471)	[1]	(57,689)		(40,643)	[1]
Prepaid expenses	(16,147)	166	[1]	(14,187)		1,103	[1]
Other current assets	40,863	5,191	[1]	66,920		7,186	[1]
Accounts payable	4,062	32,744	[1]	(107,388)		(1,169)	[1]
Interest payable	15,677	16,489	[1]	101		3,154	[1]
Income taxes payable	5,554	18,922	[1]	14,095		28,112	[1]
Other current liabilities	(14,786)	(14,461)	[1]	(44,581)		(48,972)	[1]
Net cash provided by operating activities	223,907	333,050	[1]	248,328		510,732	[1]
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	3,542	13,640	[1]	3,742		145,773	[1]
Additions to oil and gas properties	(77,623)	(319,341)	[1]	(242,150)		(616,608)	[1]
Additions to other assets and other property and equipment, net	(14,663)	(8,240)	[1]	(21,399)		(20,646)	[1]
Net cash used in investing activities	(88,744)	(313,941)	[1]	(259,807)		(491,481)	[1]
Cash flows from financing activities:
Borrowings under long-term debt	0	23,998	[1]	172,000		615,998	[1]
Principal payments on long-term debt	(102,000)	(186,998)	[1]	(103,000)		(732,775)	[1]
Distributions to noncontrolling interest partners	(5,060)	0	[1]	(9,900)		0	[1]
Proceeds from issuance of partnership common units, net of issuance costs	0	165,978	[1]	0		165,978	[1]
Borrowings (payments) of other liabilities	(364)	19,145	[1]	(699)		13,255	[1]
Exercise of long-term incentive plan stock options	1,581	4,905	[1]	2,535		5,782	[1]
Purchase of treasury stock	(280)	(562)	[1]	(20,399)		(27,512)	[1]
Excess tax (costs) benefits from share-based payment arrangements	(39)	(1,741)	[1]	(3,918)		404	[1]
Payment of financing fees	(4,475)	(1,031)	[1]	(4,475)		(12,377)	[1]
Dividends paid	(4,679)	(16,841)	[1]	(4,679)		(16,893)	[1]
Net cash provided by (used in) financing activities	(115,316)	6,853	[1]	27,465		11,860	[1]
Net increase in cash and cash equivalents	19,847	25,962	[1]	15,986		31,111	[1]
Cash and cash equivalents, beginning of period	44,476	17,320	[1]	48,337	[1]	12,171	[1]
Cash and cash equivalents, end of period	$64,323	$43,282	[1]	$64,323		$43,282	[1]
[1]Retrospectively adjusted as described in Note B.

Statement Of Other Comprehensiv

Statement Of Other Comprehensive Income (USD $)
In Thousands	3 Months Ended Jun. 30, 2009	3 Months Ended Jun. 30, 2008		6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 30, 2008
Net income (loss)	($92,114)	$162,921	[1]	($102,926)	$291,618	[1]
Hedge activity, net of tax:
Hedge fair value changes, net	0	(331,325)	[1]	14,169	(471,592)	[1]
Net hedge (gains) losses included in continuing operations	(3,032)	103,354	[1]	(33,861)	153,785	[1]
Other comprehensive loss	(3,032)	(227,971)	[1]	(19,692)	(317,807)	[1]
Comprehensive loss	(95,146)	(65,050)	[1]	(122,618)	(26,189)	[1]
Comprehensive loss attributable to noncontrolling interest	6,057	12,804	[1]	4,270	12,066	[1]
Comprehensive loss attributable to common stockholders	($89,089)	($52,246)	[1]	($118,348)	($14,123)	[1]
[1]Retrospectively adjusted as described in Note B.

Notes to Financial Statements

Notes to Financial Statements
	6 Months Ended Jun. 30, 2009 USD / shares
Notes to Financial Statements [Abstract]
NOTE A.Organization and Nature of Operations	NOTEA. Organization and Nature of Operations Pioneer 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, South Africa and Tunisia.
NOTE B.Basis of Presentation	NOTEB. Basis of Presentation Presentation. In the opinion of management, the consolidated financial statements of the Company as of June30, 2009 and for the three and six months ended June30, 2009 and 2008 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 Form 10-Q pursuant to the rules and regulations of the SEC. These consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Companys Annual Report on Form 10-K for the year ended December31, 2008. Discontinued operations. During the three months ended June30, 2009, the Company committed to a plan to sell its shelf properties in the Gulf of Mexico and sold its Mississippi assets. The Company completed the sale of its shelf properties in the Gulf of Mexico on August6, 2009. In accordance with Statement of Financial Accounting Standards (SFAS) No.144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144), the Company has classified the assets and liabilities of its shelf properties in the Gulf of Mexico as discontinued operations held for sale in the accompanying consolidated balance sheet as of June30, 2009, and reflected the results of operations of both the planned and completed divestitures as discontinued operations, rather than as a component of continuing operations. In April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries. During the three and six months ended June30, 2008, the Company continued to realize certain revenues and costs and expense increments associated with these divestitures. See Note R for additional information regarding discontinued operations. Allowances for doubtful accounts. As of June30, 2009 and December31, 2008, the Companys allowances for doubtful accounts totaled $12.2 million and $32.4 million, respectively. In accordance with SFAS No.5, Accounting for Contingencies, the Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Companys consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an esti
NOTE C.Exploratory Well Costs	NOTEC. Exploratory Well Costs The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are presented in proved properties in the consolidated balance sheets. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense. The following table reflects the Companys capitalized exploratory well activity during the three and six months ended June30, 2009: ThreeMonthsEnded June30, 2009 SixMonthsEnded June30, 2009 (in thousands) Beginning capitalized exploratory well costs $ 123,839 $ 124,014 Additions to exploratory well costs pending the determination of proved reserves 12,196 26,338 Reclassification due to determination of proved reserves (17,811 ) (27,201 ) Exploratory well costs charged to exploration expense (4,227 ) (9,154 ) Ending capitalized exploratory well costs $ 113,997 $ 113,997 The following table provides an aging, as of June30, 2009 and December31, 2008, of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed: June30,2009 December31,2008 (inthousands,exceptprojectcounts) Capitalized exploratory well costs that have been suspended: One year or less $ 20,471 $ 54,423 More than one year 93,526 69,591 $ 113,997 $ 124,014 Number of projects with exploratory well costs that have been suspended for a period greater than one year 6 4 The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of June30, 2009: Total 2009 2008 2007 2006 (in thousands) United States: Cosmopolitan Unit $ 60,495 $ 1,834 $ 6,344 $ 51,488 $ 829 Other 2,525 (282 ) 2,807 Tunisia 30,506 1,261 20,866 4,434 3,945 Total $ 93,526 $ 2,813 $ 30,017 $ 55,922 $ 4,774 Cosmopolitan Unit. The Company owns a 100 percent working interest in, and is the operator of, the Cosmopolitan Unit in the Cook Inlet of Alaska. During 2007, the Company drilled the Hansen #1A L1 well, a lateral sidetrack from an existing wellbore, to appraise the resource potential of the unit. The initial unstimulated production test results were encouraging. As a result, the Company began permitting and facilities planning during 2008 to further evaluate the units resource potential. During 2009, the Company plans to continue with permitting, progress engineering studies and develop plans for a second well to be drilled in 2010 to further delineate the extent of the units resource pote
NOTE D.Disclosures About Fair Value Measurements	NOTED. Disclosures About Fair Value Measurements The valuation framework of SFAS 157 is 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 companys own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy: Level 1 quoted prices for identical assets or liabilities in active markets. Level 2 quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means. Level 3 unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Companys assets and liabilities that are measured at fair value on a recurring basis as of June30, 2009, for each of the fair value hierarchy levels: Fair Value Measurements at Reporting Date Using FairValueat June30,2009 QuotedPricesin ActiveMarketsfor Identical Assets (Level 1) SignificantOther Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Trading securities $ 53 $ 188 $ $ 241 Commodity derivatives 96,939 7,228 104,167 Deferred compensation plan assets 23,445 23,445 Total assets $ 23,498 $ 97,127 $ 7,228 $ 127,853 Liabilities: Commodity derivatives $ $ 144,701 $ 1,762 $ 146,463 Interest rate derivatives 9,542 9,542 Total liabilities $ $ 154,243 $ 1,762 $ 156,005 The following tables present the changes in the fair values of the Companys net commodity derivative assets classified as Level 3 in the fair value hierarchy: Fair Value Measurements Using Significant Unobservable Inputs (Level 3) Three Months Ended June30, 2009 NGLSwap Contracts Gas Three-Way Collars Oil Three-Way Collars Total (in thousands) Beginning balance $ 16,470 $ (1,697 ) $ 3,364 $ 18,137 Total gains (losses) (a): Net unrealized losses included in earnings (8,666 ) (8,666 ) Net realized losses included in earnings (780 ) (780 ) Settlements (1,558 )
NOTE E.Income Taxes	NOTEE. Income Taxes The Company accounts for income taxes in accordance with the provisions of SFAS No.109, Accounting for Income Taxes (SFAS 109). SFAS 109 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 Companys net operating loss carryforwards (NOLs) and other deferred tax attributes in the U.S. federal, state and foreign tax jurisdictions will be utilized prior to their expiration. As of June30, 2009 and December31, 2008, the Companys valuation allowances (relating primarily to foreign tax jurisdictions) were $42.0 million and $37.5 million, respectively. The Company also accounts for income taxes in accordance with FASB Interpretation No.48, Accounting for Uncertainty in Income Taxes (FIN 48), which 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 June30, 2009, the Company had no unrecognized tax benefits (as defined in FIN 48). In connection with the adoption of FIN 48, the Company established a policy 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 2003. As of June30, 2009, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Companys future results of operations or financial position. On June30, 2009, pursuant to Tunisian law, the Company established an investment reserve equal to 20 percent of 2008 taxable profits on the Adam and Cherouq concessions and thereby reduced current taxes payable by $13.1 million with a corresponding offset to deferred income taxes in the Companys accompanying consolidated balance sheets. The investment reserve will be used to fund future drilling activity or pipeline infrastructure projects in Tunisia. Income tax (provisions) benefits. The Companys income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended June30, 2009 and 2008: Three Months Ended June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Current: U.S. federal $ (777 ) $ 14,328 $ 294 $ 8,908 U.S. state (6,329 ) (686 ) (7,006 ) (1,597 ) Foreign 9,220 (25,680 ) (942 ) (40,451 ) 2,114 (12,038 ) (7,654 ) (33,140 )
NOTE F.Long-term Debt	NOTEF. Long-term Debt Lines of credit. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the Credit Facility) that matures in April 2012, unless extended in accordance with the terms of the Credit Facility. The Credit Facility provides for initial aggregate loan commitments of $1.5 billion, which may be increased to a maximum aggregate amount of $2.0 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added. As of June30, 2009, the Company had $982.0 million of outstanding borrowings under the Credit Facility and $46.0 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $472.0 million of unused borrowing capacity under the Credit Facility. Effective April29, 2009, the Company and the lenders under the Companys Credit Facility amended the Credit Facility to provide the Company additional financial flexibility. The Credit Facility contains certain financial covenants, one of which required the Company to maintain a ratio of the net present value of the Companys oil and gas properties to total debt of at least 1.75 to 1.0 until the Company achieves an investment grade rating by Moodys Investors Service, Inc. or Standard Poors Ratings Group, Inc. The amendment changed that ratio to 1.5 to 1.0 through the period ending March31, 2011, after which time the ratio would revert to 1.75 to 1.0, and provides that the Company may include in the calculation of the present value of its oil and gas properties 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest. The covenant requiring the Company to maintain a ratio of total debt to total capitalization of no more than 0.60 to 1.0 was not changed. The amendment also adjusted certain borrowing rates and commitment fees, and changed certain provisions relating to the consequences if a lender under the Credit Facility defaults in its obligations under the agreement. After taking into account the amendment, 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 JPMorgan Chase Bank 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 .5 percent plus a defined alternate base rate spread margin (ABR Margin), which is currently one percent based on the Companys 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 Companys 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 .125 percent. The Company also pays commitment fees on undrawn amounts unde
NOTE G.Derivative Financial Instruments	NOTEG. Derivative Financial Instruments The Company uses financial derivative contracts to manage exposures to commodity price, interest rate and foreign currency fluctuations. The Company generally does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter physical delivery contracts to effectively provide commodity price protection. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, physical delivery contracts are not accounted for as derivative financial instruments in the financial statements. All derivatives are recorded on the balance sheet at estimated fair value. Fair value is determined in accordance with SFAS 157 and is generally determined based on the credit-adjusted present value difference between the fixed contract price and the underlying market price at the determination date. Effective February1, 2009, the Company discontinued hedge accounting on all existing derivative instruments and since that date has accounted for derivative instruments using the mark-to-market accounting method. Therefore, the Company will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur. Changes in the fair value of effective cash flow hedges prior to the Companys discontinuance of hedge accounting on February1, 2009 were recorded as a component of AOCI Hedging, which has been or will be transferred to earnings when the hedged transaction is recognized in earnings. Any ineffective portion of changes in the fair value of hedge derivatives prior to February1, 2009 was recorded in the earnings of the period of change. The ineffective portion was calculated as the difference between the change in fair value of the hedge derivative and the estimated change in cash flows from the item hedged. Fair value derivatives. The Company monitors the debt capital markets and interest rate trends to identify opportunities to enter into and terminate interest rate derivative contracts, with the objective of reducing the Companys costs of capital. As of June30, 2009 and December31, 2008, the Company was not a party to any fair value hedges. Cash flow derivatives. The Company utilizes commodity swap and collar contracts to (i)reduce the effect of price volatility on the commodities the Company produces and sells, (ii)support the Companys 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 Companys indebtedness and forward currency exchange agreements to reduce the effect of exchange rate volatility. Oil prices. All material physical sales contracts governing the Companys oil production have been tied directly or indirectly to the NYMEX prices. The following table sets forth the volumes in Bbls underlying the Companys outstanding oil derivative contracts and the weighted average NYMEX prices per Bbl for those
NOTE H.Asset Retirement Obligations	NOTEH. Asset Retirement Obligations The Companys asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Companys asset retirement obligation transactions during the three and six months ended June30, 2009 and 2008: Three Months Ended June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Beginning asset retirement obligations $ 173,516 $ 200,371 $ 172,433 $ 208,183 Liabilities assumed in acquisitions 21 21 New wells placed on production and changes in estimates (a) 15,327 630 15,366 (7,791 ) Liabilities reclassified to discontinued operations held for sale (14,353 ) (14,353 ) Disposition of wells (246 ) (246 ) Liabilities settled (23,046 ) (17,271 ) (24,976 ) (18,804 ) Accretion of discount on continuing operations 2,753 1,961 5,505 3,904 Accretion of discount on discontinued operations 220 199 442 398 Ending asset retirement obligations $ 154,171 $ 185,911 $ 154,171 $ 185,911 (a) During the six months ended June30, 2008, the Company recorded a $9.0 million decrease in the abandonment estimates and associated insurance recovery estimates for the East Cameron facility that was destroyed by Hurricane Rita in 2005. 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 June30, 2009 and December31, 2008, the current portions of the Companys asset retirement obligations were $22.7 million and $29.9 million, respectively.
NOTE I.Postretirement Benefit Obligations	NOTEI. Postretirement Benefit Obligations As of June30, 2009 and December31, 2008, the Company had $9.4 million and $9.6 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the 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 June30, 2009 or December31, 2008. Other than participants in the Companys retirement plan, the participants of these plans are not current employees of the Company. The following table reconciles changes in the Companys unfunded accumulated postretirement benefit obligations during the three and six months ended June30, 2009 and 2008: ThreeMonthsEnded June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Beginning accumulated postretirement benefit obligations $ 9,504 $ 10,401 $ 9,612 $ 10,494 Net benefit payments (362 ) (265 ) (691 ) (563 ) Service costs 57 47 114 95 Accretion of interest 165 158 329 315 Ending accumulated postretirement benefit obligations $ 9,364 $ 10,341 $ 9,364 $ 10,341
NOTE J.Commitments and Contingencies	NOTEJ. Commitments and Contingencies Legal actions. The Company is party to the legal actions that are described below. The Company is also 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 Companys 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. MOSH Holding. On April11, 2005, the Company and its principal United States subsidiary, Pioneer Natural Resources USA, Inc., were named as defendants in MOSH Holding, L.P. v Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc.; Woodside Energy (USA) Inc.; and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (the Trust), which is before the Judicial District Court of Harris County, Texas (334th Judicial District) (the Court). On April27, 2009, the Company and all parties in the lawsuit reached an agreement to settle the lawsuit. Under the terms of the settlement agreement, the Company will pay to the Trust the sum of $13 million in exchange for a full and final release of all claims made or that could have been made in the lawsuit. The Company will also contribute to the Trust proceeds obtained from the Companys sale of its complete interest, including its working interest, in the Brazos Block A-39 tract, which will be sold in conjunction with the Trusts sale of its assets. The settlement agreement is subject to customary conditions, including a condition that the settlement is not final until it is approved by the Court and the Court issues a final, non-appealable judgment disposing of all claims. On August 6, 2009, the Court issued an Interlocutory Judgment approving the settlement agreement. The Interlocutory Judgment, together with the settlement agreement and Findings of Fact and Conclusions of Law, disposes of all claims and claimants except five individuals who intervened in this lawsuit. Pioneer intends to file a motion seeking dismissal of the intervenors claims. Assuming Pioneers motion is granted, the intervenors claims will be dismissed, and a final judgment will be entered. Once such final judgment becomes non-appealable (or any timely appeals are resolved), then the settlement agreement will become final. Assuming that the intervenors claims are dismissed and no appeals are filed, it is expected that the settlement agreement will become final in the third or fourth quarter of 2009. Colorado Notice of Violation. On May13, 2008, the Company was served with a Notice of Violation/Cease and Desist Order by the State of Colorado Department of Public Health and Environmental Water Quality Control Division. The Notice alleges violations of stormwater discharge permits in the Companys Raton Basin and Lay C
NOTE K.Earnings Per Share From Continuing Operations	NOTEK. Earnings Per Share From Continuing Operations Basic earnings per share from continuing operations is computed by dividing earnings from continuing operations attributable to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted earnings per share from continuing operations reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income from continuing operations were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. During periods that the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to loss per share and conversion into common stock is assumed not to occur. The Companys earnings from continuing operations attributable to common stockholders is computed as income (loss) from continuing operations less participating share-based earnings. The following table is a reconciliation of the Companys income (loss) from continuing operations to income (loss) from continuing operations attributable to common stockholders for the three- and six-month periods ended June30, 2009 and 2008: Three Months Ended June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Income (loss) from continuing operations $ (94,845 ) $ 155,570 $ (104,687 ) $ 277,227 Participating share-based earnings (122 ) (2,247 ) (98 ) (3,498 ) Income (loss) from continuing operations attributable to common stockholders $ (94,967 ) $ 153,323 $ (104,785 ) $ 273,729 (a) In accordance with FSP EITF 03-6-1, unvested restricted stock share awards and restricted stock unit awards represent participating securities because they participate in nonforfeitable dividends with the Companys common stock. Participating share-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and restricted stock unit awards do not participate in undistributed net losses as they are not contractually obligated to do so. 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-month periods ended June30, 2009 and 2008: Three Months Ended June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Weighted average common shares outstanding (a): Basic 113,979 118,363 114,116 118,149 Dilutive common stock options (b) 332 329 Contingently issuable - performance shares (b) 83 42 Convertible notes dilution (c) 592 296 Diluted 113,979 119,370 114,116 118,816 (
NOTE L.Geographic Operating Segment Information	NOTEL. Geographic Operating Segment Information The Companys only operations are oil and gas exploration and producing activities; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable operations in the United States, South Africa and Tunisia. The following tables provide the Companys geographic operating segment data for the three and six months ended June30, 2009 and 2008. 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 and operations in Equatorial Guinea and Nigeria, where the Company concluded exploration activities during 2007. United States SouthAfrica Tunisia Headquarters Consolidated Total (in thousands) Three Months Ended June30, 2009 Revenues and other income: Oil and gas $ 314,031 $ 18,160 $ 38,501 $ $ 370,692 Interest and other 88,598 88,598 Gain on disposition of assets, net 7 46 53 314,038 18,160 38,501 88,644 459,343 Costs and expenses: Oil and gas production 75,389 445 8,959 84,793 Production and ad valorem taxes 23,715 23,715 Depletion, depreciation and amortization 132,482 20,446 5,750 7,265 165,943 Exploration and abandonments 17,978 195 3,244 201 21,618 General and administrative 33,275 33,275 Accretion of discount on asset retirement obligations 2,753 2,753 Interest 43,475 43,475 Hurricane activity, net 16,075 16,075 Derivative losses, net 170,224 170,224 Other 18,864 3,768 14,083 36,715 284,503 21,086 21,721 271,276 598,586 Income (loss) from continuing operations before income taxes 29,535 (2,926 ) 16,780 (182,632 ) (139,243 ) Income tax benefit (provision) (10,928 ) 849 (9,638 ) 64,115 44,398 Income (loss) from continuing operations $ 18,607 $ (2,077 ) $ 7,142 $ (118,517 ) $ (94,845 ) United States SouthAfrica Tunisia Headquarters Consolidated Total (in thousands) Three Months Ended June30, 2008 Revenues and other inco
NOTE M.Impairment of Oil and Gas Properties	NOTEM. Impairment of Oil and Gas Properties Oil and gas properties assessments. During the first quarter of 2009, the downward adjustments to economically recoverable resource potential in the Companys Uinta/Piceance area associated with declines in commodity prices and well performance led to the impairment of the net assets in the Companys Uinta/Piceance area. The Companys estimates of the undiscounted future cash flows attributed to the assets indicated that their carrying amounts were not expected to be recovered. Consequently, the Company recorded a $21.1 million noncash charge during the first quarter of 2009 to reduce the carrying value of the Uinta/Piceance area oil and gas properties. The impairment charge reduced the oil and gas properties carrying values to their estimated fair values, represented by the estimated discounted future cash flows attributable to the assets, which were derived from Level 2 fair value inputs. The Companys primary assumptions of the estimated future cash flows attributable to oil and gas properties are based on (i)proved reserves and risk-adjusted probable and possible reserves and (ii)managements commodity price outlook. Goodwill assessments. In accordance with SFAS 142, the Company assesses its goodwill for impairment annually during the third quarter using a July1 assessment date. The Companys assessment of goodwill during the third quarter of 2008 indicated that it was not impaired. As a result of declines in commodity prices and a significant decline in the Companys market capitalization during the second half of 2008, which the Company considered an event that might indicate impairment to the carrying value of goodwill, the Company has reassessed whether the fair value of its net assets supported the carrying value of the Companys goodwill at its United States reporting unit at December31, 2008 and quarterly thereafter. The Companys quarterly reassessments have indicated that its goodwill was not impaired. The Companys assessments of goodwill for impairment include estimates of the fair value of its United States reporting unit and comparisons of those fair value estimates with the United States reporting units carrying value. The Companys estimates of the fair value of its United States reporting unit entailed estimating the fair values of the reporting units assets and liabilities. The primary component of those assets and liabilities is comprised of the reporting units oil and gas properties, whose estimated values were based on the estimated discounted future net cash flows expected to be recovered from the properties. The Companys primary assumptions in preparing the estimated discounted future net cash flows expected to be recovered from the properties are based on (i)proved reserves and risk-adjusted probable reserves, (ii)managements price outlook, including assumptions as to inflation of costs and expenses, (iii)the Companys weighted average cost of capital and (iv)future income tax expense attributable to the net cash flows. Due to the significant decline in the Companys market capitalization, the Company expanded its assessment of goodwill impairment to consider the fai
NOTE N.Volumetric Production Payments	NOTEN. Volumetric Production Payments During 2005, the Company sold 27.8 MMBOE of proved reserves by means of three VPP agreements for net proceeds of $892.6 million, including the assignment of the Companys obligations under certain derivative hedge agreements. Proceeds from the VPPs were used to reduce outstanding indebtedness. The first VPP sold 58 Bcf of gas volumes over an expected five-year term that began in February 2005. The second VPP sold 10.8 MMBbls of oil volumes over an expected seven-year term that began in January 2006. The third VPP sold 6.0 Bcf of gas volumes over an expected 32-month term from May 2005 through December 2007, and 6.2 MMBbls of oil volumes over an expected five-year term that began in January 2006. The Companys VPPs represent limited-term overriding royalty interests in oil and gas reserves that: (i)entitle the purchaser to receive production volumes over a period of time from specific lease interests, (ii)are free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii)are nonrecourse to the Company (i.e., the purchasers 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 VPPs volumetric quantities have been delivered. Under SFAS No.19, Financial Accounting and Reporting by Oil and Gas Producing Companies, a VPP is considered a sale of proved reserves. As a result, the Company (i)removed the proved reserves associated with the VPPs, (ii)recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil and gas revenues over the term of each 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 the deferred revenue carrying values of the Companys VPPs. Gas Oil Total (in thousands) Deferred revenue at December31, 2008 $ 49,435 $ 275,706 $ 325,141 Less: 2009 amortization (24,514 ) (49,180 ) (73,694 ) Deferred revenue at June30, 2009 $ 24,921 $ 226,526 $ 251,447 The above deferred revenue amounts will be recognized in oil and gas revenues in the consolidated statements of operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands): Remaining 2009 $ 74,212 2010 90,215 2011 44,951 2012 42,069 $ 251,447
NOTE O.Interest and Other Income	NOTEO. Interest and Other Income The following table provides the components of the Companys interest and other income: ThreeMonthsEnded June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Alaskan Petroleum Production Tax credits (a) $ 87,511 $ 6,605 $ 94,989 $ 17,770 Interest income 749 376 1,379 860 Other income 795 437 959 1,769 Deferred compensation plan income 74 174 861 1,546 Foreign currency remeasurement and exchange gains (b) (735 ) (988 ) 617 2,526 Credit card rebate 204 285 453 554 Change in asset retirement estimate 4,391 Legal settlements (2 ) 2,495 Total interest and other income $ 88,598 $ 6,887 $ 99,258 $ 31,911 (a) The Company earns Alaskan Petroleum Production Tax (PPT) credits on qualifying capital expenditures. The Company recognizes income from PPT credits at the time they are realized through a cash refund or sale. (b) The Companys operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.
NOTE P.Other Expense	NOTEP. Other Expense The following table provides the components of the Companys other expense: ThreeMonthsEnded June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Idle rig related costs (a) $ 22,632 $ 6,975 $ 42,918 $ 14,836 Transportation commitment loss (b) 6,781 6,781 Contingency and environmental accrual adjustments 262 63 6,086 507 Well servicing operations (c) 2,391 895 5,382 1,638 Foreign currency remeasurement and exchange losses (d) 3,408 (35 ) 4,733 338 Inventory impairment (e) 433 1,603 Other 866 (882 ) 1,345 (357 ) Bad debt expense (58 ) 1,259 (744 ) 3,228 Total other expense $ 36,715 $ 8,275 $ 68,104 $ 20,190 (a) Represents stacked drilling rig costs under contractual drilling rig commitments and costs incurred to terminate contractual drilling rig commitments prior to their contractual maturities. (b) Primarily represents transportation contract deficiency payment obligations not supported by future production. (c) Represents idle well servicing costs. (d) The Companys operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses. (e) Represents impairment charges to reduce the carrying value of excess lease and well equipment and supplies inventories to their estimated net realizable values.
NOTE Q.Insurance Claims	NOTEQ. Insurance Claims As a result of Hurricane Rita in September 2005, the Companys East Cameron facility, located in the Gulf of Mexico shelf, was destroyed. As of June30, 2009, the Company estimated that it will cost approximately $16 million to $21 million to complete the reclamation and abandonment of the East Cameron facility. The operations to reclaim and abandon the East Cameron facilities began in January 2007. The estimate of the remaining costs to reclaim and abandon the East Cameron facility is based upon an estimate by the Company. The remaining estimated cost to reclaim and abandon the East Cameron facilities contains a number of assumptions that could cause the ultimate cost to be higher or lower than the estimate, as there are many uncertainties when working offshore and underwater with damaged equipment and wellbores. The Company has expended approximately $182.0 million on the reclamation and abandonment of the East Cameron facility through June30, 2009. During the three months ended June30, 2009, the Company recorded a $15.0 million noncash charge to hurricane activity, net in the accompanying statements of operations to increase its estimate of the total costs to reclaim and abandon the East Cameron facility. The Company filed a claim with its insurance providers regarding the loss at East Cameron. Under the Companys insurance policies, the East Cameron facility had the following coverages: (a)$14 million of scheduled property value for the platform, which was received in 2005, (b)$4 million of scheduled business interruption insurance after a deductible waiting period, which was received in 2006, (c)$100 million of well restoration and safety, in total, for all assets per occurrence and (d)$400 million for debris removal coverage for all assets per occurrence. For the six months ended June30, 2009, the Company has received $11.6 million from one of its insurance providers related to debris removal, which reduced the Companys recorded receivable. At the present, no recoveries have been reflected related to certain costs associated with plugging and abandonment and the well restoration and safety coverages. In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues, primarily related to debris removal, certain costs associated with plugging and abandonment, and the well restoration and safety coverages. The Company continues to expect that a substantial portion of the loss will be recoverable from insurance.
NOTE R.Discontinued Operations	NOTER. Discontinued Operations During the three months ended June30, 2009, the Company committed to a plan to sell its shelf properties in the Gulf of Mexico and sold its Mississippi assets. The Company completed the sale of its shelf properties in the Gulf of Mexico on August6, 2009. Pursuant to SFAS 144, the Company has reflected the results of operations of these transactions as discontinued operations, rather than as a component of continuing operations. Additionally, in April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries. During the three and six months ended June30, 2008, the Company continued to realize certain revenues and costs and expense increments associated with these divestitures. The following table represents the components of the Companys discontinued operations for the three and six month periods ended June30, 2009 and 2008: Three Months Ended June30, Six Months Ended June30, 2009 2008 2009 2008 (in thousands) Revenues and other income: Oil and gas $ 5,736 $ 18,186 $ 11,722 $ 34,619 Interest and other 86 1,989 Gain (loss) on disposition of assets, net (a) 306 (72 ) 306 (6 ) 6,042 18,200 12,028 36,602 Costs and expenses: Oil and gas production 2,109 1,469 4,649 3,275 Production and ad valorem taxes 60 74 118 214 Depletion, depreciation and amortization (a) (551 ) 2,428 3,862 7,418 Exploration and abandonments (a) 22 3,980 283 5,472 General and administrative (21 ) (2 ) (36 ) 215 Accretion of discount on asset retirement obligations (a) 220 199 442 398 Other (433 ) (389 ) 1,839 7,715 9,318 16,603 Income from discontinued operations before income taxes 4,203 10,485 2,710 19,999 Income tax benefit (provision): Current 348 (171 ) Deferred (a) (1,472 ) (3,482 ) (949 ) (5,437 ) Income from discontinued operations $ 2,731 $ 7,351 $ 1,761 $ 14,391 (a) Represents the significant noncash components of discontinued operations. At June30, 2009, the carrying values of the assets and liabilities of the Companys Gulf of Mexico shelf operations are included in discontinued operations held for sale in the accompanying consolidated balance sheet and are comprised of the following (in thousands): Composition of assets included in discontinued operations held for sale: Current assets $ 2,870 Property, plant and equipment, net 13,385 Other assets, net 619 Total assets $ 16,874 Composition of lia
NOTE S.Subsequent Events	NOTES. Subsequent Events In accordance with SFAS 165, the Company has evaluated subsequent events through August7, 2009, the date of issuance of the unaudited consolidated financial statements. The Company is not aware of any reportable subsequent events through August7, 2009, except as disclosed in Notes J and R.

Document Information

Document Information
	6 Months Ended Jun. 30, 2009 USD / shares
Document Information [Text Block]
Document Type	10-Q
Amendment Flag	false
Amendment Description	N.A.
Document Period End Date	2009-06-30

Entity Information

Entity Information (USD $)
	6 Months Ended Jun. 30, 2009	Aug. 06, 2009	Jun. 30, 2008
Entity [Text Block]
Trading Symbol	PXD
Entity Registrant Name	PIONEER NATURAL RESOURCES CO
Entity Central Index Key	0001038357
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		115,064,128
Entity Public Float			$9,166,300,086