Pioneer Natural Resources (PXD) 10-K 19 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document Information [Line Items]
Entity Registrant Name	Pioneer Natural Resources Company
Trading Symbol	PXD
Entity Central Index Key	1,038,357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		163,266,510
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 20,541,004,904

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 1,391	$ 1,025
Accounts receivable:
Trade, net		384	436
Due from affiliates		1	4
Income taxes receivable		43	23
Inventories		155	241
Prepaid expenses		17	15
Notes receivable		498	0
Other current assets:
Derivatives		694	578
Other		11	37
Total current assets		3,194	2,359
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		16,631	15,662
Unproved properties		169	159
Accumulated depletion, depreciation and amortization		(6,778)	(5,431)
Total property, plant and equipment		10,022	10,390
Goodwill		272	272
Property, Plant and Equipment, Net	[1]	1,523	1,391
Other assets:
Investment in unconsolidated affiliate		0	239
Derivatives		64	181
Other, net		79	77
Assets, Total		15,154	14,909
Accounts payable:
Trade		798	1,197
Due to affiliates		85	123
Interest payable		65	40
Income taxes payable		2	1
Other current liabilities:
Long-term Debt, Current Maturities		448	0
Derivatives		0	3
Other		64	55
Total current liabilities		1,462	1,419
Long-term Debt, Excluding Current Maturities		3,207	2,648
Derivatives		1	2
Deferred income taxes		1,776	1,964
Other liabilities		333	287
Stockholders' equity:
Common stock, $.01 par value		2	2
Additional paid-in capital		6,267	6,167
Treasury stock, at cost		(199)	(171)
Retained earnings		2,298	2,583
Total stockholders' equity attributable to common stockholders		8,368	8,581
Noncontrolling interest in consolidating subsidiaries		7	8
Total stockholders' equity		8,375	8,589
Liabilities and Stockholders' Equity, Total		$ 15,154	$ 14,909
[1]	At December 31, 2015 and 2014, other property and equipment was net of accumulated depreciation of $711 million and $563 million, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	152,775,920	152,158,428
Treasury stock, shares	3,396,220	3,253,781

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and other income:
Oil and Gas Revenue	$ 2,178	$ 3,599	$ 3,088
Sales of purchased oil and gas	964	726	334
Interest and other	22	26	23
Derivative gains, net	879	712	4
Gain on disposition of assets, net	782	9	209
Revenues	4,825	5,072	3,658
Costs and expenses:
Oil and Gas Production Expense	717	693	588
Production and ad valorem taxes	145	220	192
Depletion, depreciation and amortization	1,385	1,047	889
Purchased oil and gas	1,003	703	336
Impairment of oil and gas properties	1,056	0	1,495
Exploration and abandonments	99	177	97
General and administrative	327	333	296
Accretion of discount on asset retirement obligations	12	12	12
Interest	187	184	184
Other	315	106	143
Costs and expenses, Total	5,246	3,475	4,232
Income (loss) from continuing operations before income taxes	(421)	1,597	(574)
Income tax benefit (provision)	155	(556)	213
Income (loss) from continuing operations	(266)	1,041	(361)
Loss from discontinued operations, net of tax	(7)	(111)	(438)
Net income (loss)	(273)	930	(799)
Net income attributable to noncontrolling interests	0	0	(39)
Net income (loss) attributable to common stockholders	$ (273)	$ 930	$ (838)
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ (1.79)	$ 7.17	$ (2.94)
Loss from discontinued operations attributable to common stockholders	(0.04)	(0.77)	(3.22)
Net income (loss) attributable to common stockholders	(1.83)	6.40	(6.16)
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	(1.79)	7.15	(2.94)
Loss from discontinued operations attributable to common stockholders	(0.04)	(0.77)	(3.22)
Net income (loss) attributable to common stockholders	$ (1.83)	$ 6.38	$ (6.16)
Weighted average shares outstanding:
Basic	149	144	136
Diluted	149	144	136
Amounts attributable to common stockholders:
Net income (loss)	$ (273)	$ 930	$ (838)

Consolidated Statements Of Stoc

Consolidated Statements Of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]	Pioneer Southwest [Member]Additional Paid-In Capital [Member]
Beginning Balance at Dec. 31, 2012	$ 5,867	$ 1	$ 3,684	$ (510)	$ 2,514	$ 178
Beginning Balance, shares at Dec. 31, 2012	123,356
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, New Issues	10,350
Issuance of Common Stock	$ 1,281	0	1,281
Dividends declared ($0.08 per share)	$ (11)				(11)
Exercise of long-term incentive plan stock options and employee stock purchases, shares	222
Exercise of long-term incentive plan stock options and employee stock purchases	$ 10		0	10	0
Purchase of treasury stock, shares	(154)
Purchase of treasury stock	$ (20)			(20)		0
Conversion of 2.875% senior convertible notes, shares	4,381
Stock Issued During Period, Value, Conversion of Convertible Securities	$ 0		(197)	197
Deferred tax benefit related to conversion of 2.875% senior convertible notes	38
Tax benefits related to stock-based compensation	$ 18		18
Issuance of treasury stock to acquire outstanding PSE units, shares	3,956
Issuance of treasury stock to acquire outstanding PSE units	$ 0		(179)	179
Pioneer Southwest merger transaction costs	(4)		(4)				$ (4)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	0		169			(169)	169
Deferred tax benefit associated with the Pioneer Southwest merger	$ 200		200				200
Compensation costs:
Vested compensation awards, net, shares	517
Vested compensation awards, net	$ 0	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition	71		70			(1)
Cash distributions to noncontrolling interests	(36)					(36)
Net income (loss)	(799)				(838)	39
Ending Balance at Dec. 31, 2013	$ 6,615	1	5,080	(144)	1,665	13
Ending Balance, shares at Dec. 31, 2013	142,628
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, New Issues	5,750
Issuance of Common Stock	$ 980	1	979
Dividends declared ($0.08 per share)	$ (12)				(12)
Exercise of long-term incentive plan stock options and employee stock purchases, shares	130
Exercise of long-term incentive plan stock options and employee stock purchases	$ 13		6	7	0
Purchase of treasury stock, shares	(178)
Purchase of treasury stock	$ (34)			(34)		0
Noncontrolling Interest, Decrease from Deconsolidation	4					4
Tax benefits related to stock-based compensation	19		19
Pioneer Southwest merger transaction costs	(1)		(1)				$ (1)
Deferred tax benefit associated with the Pioneer Southwest merger	$ 0
Compensation costs:
Vested compensation awards, net, shares	575
Vested compensation awards, net	$ 0	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition	84		84			0
Cash distributions to noncontrolling interests	(1)					(1)
Net income (loss)	930				930	0
Ending Balance at Dec. 31, 2014	$ 8,589	2	6,167	(171)	2,583	8
Ending Balance, shares at Dec. 31, 2014	148,905
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends declared ($0.08 per share)	$ (12)				(12)
Exercise of long-term incentive plan stock options and employee stock purchases, shares	58
Exercise of long-term incentive plan stock options and employee stock purchases	$ 6		3	3	0
Purchase of treasury stock, shares	(201)
Purchase of treasury stock	$ (31)			(31)
Tax benefits related to stock-based compensation	7		7
Deferred tax benefit associated with the Pioneer Southwest merger	$ 0
Compensation costs:
Vested compensation awards, net, shares	618
Vested compensation awards, net	$ 0	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition	90		90			0
Cash distributions to noncontrolling interests	(1)					(1)
Net income (loss)	(273)				(273)	0
Ending Balance at Dec. 31, 2015	$ 8,375	$ 2	$ 6,267	$ (199)	$ 2,298	$ 7
Ending Balance, shares at Dec. 31, 2015	149,380

Consolidated Statements Of Sto6

Consolidated Statements Of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Dividends declared, per share	$ 0.08	$ 0.08	$ 0.08

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (273)	$ 930	$ (799)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	1,385	1,047	889
Impairment of oil and gas properties	1,056	0	1,495
Impairment of inventory and other property and equipment	86	8	62
Exploration expenses, including dry holes	28	90	21
Deferred income taxes	(178)	552	(224)
Gain on disposition of assets, net	(782)	(9)	(209)
Accretion of discount on asset retirement obligations	12	12	12
Discontinued operations	(4)	251	633
Interest expense	18	17	17
Derivative related activity	(3)	(609)	164
Amortization of stock-based compensation	90	84	71
Other	38	34	(6)
Change in operating assets and liabilities
Accounts receivable, net	54	(29)	(123)
Income taxes receivable	(20)	(18)	3
Inventories	8	(37)	(39)
Prepaid expenses	(2)	(3)	(1)
Other current assets	2	1	4
Accounts payable	(258)	104	209
Interest payable	25	(22)	(6)
Income taxes payable	1	1	0
Other current liabilities	(35)	(38)	(27)
Net cash provided by operating activities	1,248	2,366	2,146
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	553	877	711
Distribution from (investment in) unconsolidated subsidiary	0	0	25
Additions to oil and gas properties	(2,110)	(3,243)	(2,639)
Additions to other assets and other property and equipment, net	(283)	(333)	(237)
Net cash used in investing activities	(1,840)	(2,699)	(2,140)
Cash flows from financing activities:
Borrowings under long-term debt	998	523	467
Principal payments on long-term debt	0	(523)	(1,547)
Proceeds from Issuance of Common Stock	0	980	1,281
Distributions to noncontrolling interests	(1)	(1)	(36)
Payments of other liabilities	0	0	(4)
Exercise of long-term incentive plan stock options and employee stock purchases	6	13	10
Purchase of treasury stock	(31)	(34)	(20)
Excess tax benefits from share-based payment arrangements	7	19	18
Payment of financing fees	(9)	0	0
Dividends paid	(12)	(12)	(11)
Net cash provided by financing activities	958	965	158
Net increase (decrease) in cash and cash equivalents	366	632	164
Cash and cash equivalents, beginning of period	1,025	393	229
Cash and cash equivalents, end of period	$ 1,391	$ 1,025	$ 393

Organization And Nature Of Oper

Organization And Nature Of Operations	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization And Nature Of Operations	NOTE A. Organization and Nature of Operations Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company operating in the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeast Colorado and the West Panhandle field in the Texas Panhandle. The Company's objective is to maximize shareholder investment returns by maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	NOTE B. Summary of Significant Accounting Policies Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the 2014 and 2013 financial statement and footnote amounts in order to conform them to the 2015 presentations. Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized. Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less. Accounts receivable. As of December 31, 2015 and 2014 , the Company had accounts receivable – trade, net of allowances for bad debts, of $384 million and $436 million , respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. As of both December 31, 2015 and 2014 , the Company's allowances for doubtful accounts totaled $1 million . The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable 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 Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, natural gas liquids ("NGLs") and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. The following table presents the Company's materials and supplies and commodity inventories as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in millions) Materials and supplies (a) $ 132 $ 223 Commodities 23 18 $ 155 $ 241 ____________________ (a) As of December 31, 2015 and 2014 , the Company's materials and supplies inventories were net of valuation allowances of $78 million and $22 million , respectively. See Note D for additional information regarding inventory impairments. Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) The well has found a sufficient quantity of reserves to justify its completion as a producing well; and (ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs. The Company owns interests in seven gas processing plants and eight treating facilities. The Company is the operator of one of the gas processing plants and all eight of the treating facilities. Six of the gas processing plants are operated by third parties and six of the treating facilities are not currently being used. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities in continuing operations for the years ended December 31, 2015 , 2014 and 2013 were $39 million , $56 million and $53 million , respectively. Third party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $27 million , $24 million and $21 million . The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's impairment of proved oil and gas properties. Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time. Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but 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 to the impaired value with a corresponding charge to earnings in the period in which it is determined to be impaired. During the third quarter of 2015 , the Company performed a quantitative assessment of goodwill and determined that there was no impairment. The Company reevaluated this assessment during the fourth quarter of 2015 due to reductions in (i) management's longer-term commodity price outlooks ("Management's Price Outlooks") and (ii) the Company's common stock price. Based upon the results of this qualitative assessment, the Company determined that it was more likely than not that the Company's goodwill was not impaired. Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2015 and 2014 , respectively, the net carrying value of other property and equipment consisted of the following: As of December 31, 2015 (a) 2014 (a) (in millions) Proved and unproved sand properties (b) $ 473 $ 469 Land and buildings 468 440 Equipment and rigs (c) 287 338 Water infrastructure (d) 180 10 Vehicles 21 35 Furniture and fixtures 67 70 Leasehold improvements 27 29 $ 1,523 $ 1,391 ____________________ (a) At December 31, 2015 and 2014 , other property and equipment was net of accumulated depreciation of $711 million and $563 million , respectively. (b) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. (c) Includes well servicing equipment and rigs and fracture stimulation equipment that are owned by wholly-owned subsidiaries that provide pumping and well services on Company-operated properties. As of December 31, 2015 , the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. (d) Includes water supply wells and pipeline infrastructure costs. The primary purposes of the Company's sand mines and pumping and well services operations are to accommodate the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. All intercompany gains or losses of the Company's sand mines and pumping and well services operations are eliminated. The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years. Equipment and rigs, vehicles, and furniture and fixtures are generally depreciated over two to 15 years. Water infrastructure is generally depreciated over 10 to 50 years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method. Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party. In July 2015, the Company sold its remaining 50.1 percent interest in EFS Midstream to an unaffiliated third party. See Note C for additional information regarding the Company's divestitures. Prior to the sale, the Company did not have control of EFS Midstream. Consequently, the Company accounted for this 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 member interests sold and the investor's share of the investee's net losses. The Company's equity interest in the net income or loss of EFS Midstream (prior to its sale) was recorded in interest and other income, net of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income of EFS Midstream for the years ended December 31, 2015 , 2014 and 2013 . Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated. 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 and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations. Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. Issuance of common stock. In November 2014 and February 2013, the Company issued 5.75 million shares and 10.35 million shares of its common stock, respectively, and realized cash proceeds of $980 million and $1.3 billion , respectively, net of associated underwriting and offering expenses. Noncontrolling interest in consolidated subsidiaries. The Company owns the majority interests in certain subsidiaries with operations in the United States. Prior to December 17, 2013, the Company owned a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest") and consolidated the financial position, results of operations and cash flows of Pioneer Southwest with those of Pioneer. Pioneer Southwest owned proved and unproved oil and gas properties in the Spraberry field in the Permian Basin of West Texas. On December 17, 2013, the holders of a majority of the outstanding common units of Pioneer Southwest approved an amended agreement and plan of merger, pursuant to which (i) all of the then outstanding common units of Pioneer Southwest were canceled and converted into the right to receive 0.2325 of a share of common stock of the Company and (ii) Pioneer Southwest became a wholly-owned subsidiary of the Company. The changes in the Company's ownership of Pioneer Southwest were accounted for by eliminating the noncontrolling interest attributable to Pioneer Southwest. See Note C for additional information about Pioneer Southwest and the amended agreement and plan of merger. Noncontrolling interests in the net assets of consolidated subsidiaries totaled $7 million and $8 million as of December 31, 2015 and 2014 , respectively. For the years ended December 31, 2015 and December 31, 2014 , the Company recorded nominal net losses attributable to the noncontrolling interests, as compared to $39 million of net income attributable to the noncontrolling interests for the years ended December 31, 2013 . The decrease in income attributable to noncontrolling interests for the years ended December 31, 2015 and 2014 , as compared 2013 , is due to the Company's acquisition of all of the outstanding common units of Pioneer Southwest not owned by the Company in December 2013. The Company records transfers of any gains or losses, net of taxes, from noncontrolling interests in consolidated subsidiaries to additional paid in capital in an amount proportionate to the ownership of those noncontrolling interests after giving effect to the purchase or sale of common units. There were no transfers of gains or losses, net of tax, from noncontrolling interest to additional paid in capital during 2015. The effect of transfers of gains or losses, net of tax, from noncontrolling interest to additional paid in capital was a decrease of $1 million in 2014 associated with Pioneer Southwest merger transaction costs and an increase of $365 million in 2013, comprised of (i) an increase of $169 million to record the acquisition of noncontrolling interest of Pioneer Southwest, (ii) an increase of $200 million to recognize deferred taxes associated with the Pioneer Southwest acquisition and (iii) a decrease of $4 million associated with Pioneer Southwest merger transaction costs. Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2015 or 2014 . The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate ("WTI") oil sales to a Gulf Coast market price and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N for further information on transportation commitment charges. Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. 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. See Note E for additional information about the Company's derivative instruments. Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs. Stock-based compensation. Stock-based compensation expense is being recognized on restricted stock, restricted stock units, performance units and stock option awards that are expected to be settled in the Company's common stock ("Equity Awards") 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 or modification, as applicable. Stock-based compensation awards generally vest over a period of three years. The amount of stock-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date. Stock-based compensation liability awards ("Liability Awards") are restricted stock awards that are expected to be settled in cash on their vesting dates, rather than in common stock. Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value 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 vested portions of the awards are recorded as increases or decreases to stock-based compensation expense. 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 to measure the fair value of Equity Awards and Liability Awards, (iii) the closing stock price on the balance sheet date to measure the fair value of the vested portions of Liability Awards and (iv) the Monte Carlo simulation method to measure the fair value of performance unit awards. Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell. In addition, after determining that held for sale criteria has been met, the Company considers whether the assets held for sale meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of tax in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional information about the Company's divestitures. Restructuring. In May 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. The restructuring plan was substantially complete as of December 31, 2015. In connection therewith, during the year ended December 31, 2015 , the Company recognized $23 million of restructuring charges in other expense in the accompanying consolidated statements of operations. The restructuring costs included $17 million in employee severance costs and $6 million in office lease-related costs. Employee severance costs. The $17 million of employee severance costs was based on the number of employees impacted by the restructuring, with $16 million related to cash severance payments and $1 million related to accelerated vesting of share-based grants, which were noncash charges. Lease obligations and other . The $6 million of office lease-related costs relates to certain Denver office space that will no longer be used, of which $2 million represents the impairment of leasehold improvements and $4 million represents the Company's future obligations under the operating leases, net of anticipated sublease income. As of December 31, 2015 , the Company had $4 million of restructuring liabilities, primarily related to future lease obligations recorded in other current and noncurrent liabilities in the accompanying consolidated balance sheets. New accounting pronouncements. Recently Adopted Accounting Pronouncements In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, "Balance Sheet Classification of Deferred Taxes." ASU 2015-17 requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is required to be adopted by all public companies for all annual and interim reporting periods beginning after December 15, 2016. Early adoption of this standard was permitted and the Company elected to adopt this standard, on a retrospective basis, during the fourth quarter of 2015. The adoption of ASU 2015-17 only affects the presentation of the Company's accompanying consolidated balance sheets and related financial statement disclosure in Note O. In conjunction with the adoption of ASU 2015-17, the December 31, 2014 consolidated balance sheet has been restated to reclassify $161 million of current deferred income tax liabilities to noncurrent deferred tax liabilities. In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs." ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to ASU 2015-03, debt issuance costs were required to be recognized as deferred charges and recorded as assets. ASU 2015-03 is required to be adopted by all public companies for all annual and interim reporting periods beginning after December 15, 2015. Early adoption of this standard was permitted and the Company elected to adopt this standard, on a retrospective basis, during the fourth quarter of 2015. The adoption of ASU 2015-03 only affects the presentation of the Company's accompanying consolidated balance sheets and related financial statement disclosures in Note G. In conjunction with the adoption of ASU 2015-03, the December 31, 2014 consolidated balance sheet has been restated to reclassify $17 million of debt issuance costs previously presented as part of other assets to be included as part of long-term debt. In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 restricts the presentation of discontinued operations to business circumstances when the disposal of business operations represents a strategic shift that has or will have a major effect on an entity's operating and financial results. The new guidance also expands the required disclosures for entities that have assets held for sale but do not meet the new definition of discontinued operations. The Company prospectively adopted this standard effective January 1, 2015. The adoption of this standard did not have a material

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisition and Divestitures [Text Block]	NOTE C. Acquisitions and Divestitures Acquisitions Affiliated Partnerships. In December 2014, the Company acquired the remaining limited partner interests in five affiliated partnerships for $54 million and caused the partnerships to be merged with and into a wholly-owned subsidiary of the Company. Pioneer Southwest Merger Transaction. In December 2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest not already owned by the Company, through a merger of a wholly-owned subsidiary of the Company into Pioneer Southwest, the result of which was that Pioneer Southwest became a wholly-owned subsidiary of the Company. All of the common units outstanding as of the closing of the merger, except for the common units owned by the Company, were canceled and converted into the right to receive 0.2325 of a share of common stock of the Company per common unit. Consequently, in December 2013, the Company issued an aggregate of 3.96 million shares of its common stock to Pioneer Southwest unitholders. The Company subsequently caused Pioneer Southwest, its general partner and all of Pioneer Southwest's subsidiaries to be merged with and into a wholly-owned subsidiary of the Company, the result of which was that all common units of Pioneer Southwest were canceled and the Company no longer holds any common units. Divestitures Recorded in Continuing Operations The Company recorded net gains on the disposition of assets in continuing operations of $782 million , $9 million and $209 million during the years ended December 31, 2015 , 2014 and 2013 , respectively. The following describes the significant divestitures included in continuing operations: • EFS Midstream. In November 2014, the Company announced that it was pursuing the divestment of its 50.1 percent equity interest in EFS Midstream, which was accounted for under the equity method of accounting for investments in unconsolidated affiliates. In July 2015, the Company completed the sale of its interest in EFS Midstream to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion , of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016. The amount to be received in July 2016, less imputed interest, is included in notes receivable in the accompanying consolidated balance sheets and represents a noncash investing activity. Associated with the sale, the Company recorded a pretax gain of $777 million during 2015. • Vertical drilling rigs. During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner. At December 31, 2013, the assets and liabilities of Sendero were classified as held for sale at their estimated fair value. In March 2014, the Company completed the sale of Sendero for cash proceeds of $31 million , which resulted in a gain of $1 million . As part of the sales agreement, the Company committed to lease from Sendero 12 vertical rigs through December 31, 2015 and eight vertical rigs in 2016. During the years ended December 31, 2015 and 2014, the Company incurred $40 million and $7 million , respectively, of idle drilling rig fees related to the leased Sendero rigs. See Note D and Note N for additional information about the impairment charges and idle drilling rig fees, respectively, related to Sendero. • Permian Basin. During February 2014, the Company completed the sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million , which resulted in a gain of $2 million . • Southern Wolfcamp . In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem") to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas for total consideration of $1.8 billion . In May 2013, the Company completed the sale for cash proceeds of $624 million , which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play. At December 31, 2015, the unused carry balance totaled $197 million . • West Panhandle. During the first quarter of 2013, the Company completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38 million , which resulted in a gain of $22 million . • Other. During 2015 , 2014 and 2013 , the Company sold other proved and unproved properties, inventory and other property and equipment and recorded net gains of $5 million , $6 million and $6 million , respectively. Divestitures Recorded in Discontinued Operations The Company has reflected the results of operations of its Hugoton assets, its Barnett Shale assets and Pioneer Alaska (prior to their sale) as discontinued operations in the accompanying consolidated statements of operations. Hugoton. In September 2014, the Company completed the sale of its net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million , including normal closing adjustments. Barnett Shale. In September 2014, the Company completed the sale of its Barnett Shale net assets for cash proceeds of $150 million , including normal closing adjustments. Also included in discontinued operations in 2013 is the sale of the Company's interest in certain proved and unproved oil and gas properties in the Barnett Shale field for net cash proceeds of $34 million , which resulted in a gain of $9 million on the unproved properties sold. Alaska. In April 2014, the Company completed the sale of its 100 percent interest in the capital stock of Pioneer's Alaskan subsidiary ("Pioneer Alaska") for cash proceeds of $267 million , including normal closing and other adjustments. The following table represents the components of the Company's discontinued operations for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Revenues and other income (a) $ 1 $ 238 $ 376 Costs and expenses (b) 10 409 1,063 Loss from discontinued operations before income taxes (9 ) (171 ) (687 ) Current tax provision (1 ) — (6 ) Deferred tax benefit 3 60 255 Loss from discontinued operations, net of tax $ (7 ) $ (111 ) $ (438 ) ____________________ (a) Revenues and other income for the years ended December 31, 2014 and 2013 were primarily comprised of oil and gas revenues of $198 million and $329 million , respectively. (b) Costs and expenses during 2015 were primarily related to an arbitration award associated with plugging and abandonment obligations for two Gulf of Mexico wells from which Pioneer withdrew in 2009. The Company incurred noncash impairment charges of $305 million and $729 million during the years ended December 31, 2014 and 2013, respectively, on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 and 2013 also included oil and gas production costs of $60 million and $117 million , respectively. See Note D for additional information regarding the noncash impairment charges related to the Hugoton assets, the Barnett Shale assets and Pioneer Alaska.

Disclosures About Fair Value Me

Disclosures About Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Disclosures About Fair Value Measurements	NOTE D. Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows: • Level 1 – quoted prices for identical assets or liabilities in active markets. • Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means. • Level 3 – unobservable inputs for the asset or liability. Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 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 December 31, 2015 (in millions) Assets: Commodity derivatives $ — $ 758 $ — $ 758 Deferred compensation plan assets 73 — — 73 Total assets 73 758 — 831 Liabilities: Commodity derivatives — 1 — 1 Total liabilities — 1 — 1 Total recurring fair value measurements $ 73 $ 757 $ — $ 830 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Fair Value at December 31, 2014 (in millions) Assets: Commodity derivatives $ — $ 759 $ — $ 759 Deferred compensation plan assets 70 — — 70 Total assets 70 759 — 829 Liabilities: Commodity derivatives — 2 — 2 Interest rate derivatives — 3 — 3 Total liabilities — 5 — 5 Total recurring fair value measurements $ 70 $ 754 $ — $ 824 Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represented Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives. The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and collar contracts with short puts, which is based on active and independent market-quoted volatility factors. Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of December 31, 2015 and 2014 , the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Interest rate derivatives. As of December 31, 2015 the Company had no interest rate derivative assets or liabilities. The Company's interest rate derivative liabilities as of December 31, 2014 represented Treasury rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of December 31, 2014 were based on (i) the contracted notional amounts, (ii) United States Treasury yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represented Level 2 inputs in the hierarchy priority. Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. Inventories. During the years ended December 31, 2015 , 2014 and 2013 the Company recognized impairment charges of $71 million , $8 million and $23 million , respectively, primarily to reduce the carrying value of its excess well pipe inventory. The Company calculated the estimated fair value of the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charges are included in other expense in the Company's accompanying consolidated statements of operations. Proved oil and gas properties. As a result of the Company’s proved property impairment assessments, the Company recognized pretax, noncash impairment charges to reduce the carrying values of (i) the Eagle Ford Shale field, the West Panhandle field and the South Texas - Other field during the year ended December 31, 2015 and (ii) the Raton field during the year ended December 31, 2013 to their estimated fair values. The Company calculated the fair values of the Eagle Ford Shale field, the West Panhandle field, the South Texas - Other field and the Raton field proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included Management's Price Outlooks and management's outlooks for (i) production costs, (ii) capital expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. The following table presents the fair value and fair value adjustments (in millions) for the Company's 2015 and 2013 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks: Fair Fair Value Management's Price Outlooks Value Adjustment Oil Gas South Texas - Eagle Ford Shale December 2015 $ 483 $ (846 ) $ 52.82 $ 3.34 South Texas - Other September 2015 $ 88 $ (72 ) $ 57.41 $ 3.46 West Panhandle March 2015 $ 61 $ (138 ) $ 65.02 $ 3.83 Raton December 2013 $ 534 $ (1,495 ) $ 80.40 $ 4.43 It is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future adjustments, both positive and negative, to proved and risk-adjusted probable and possible oil and gas reserves, (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields. Assets associated with divestitures. Long-lived assets that are classified as held for sale are recorded at the lower of the asset's net carrying amount or estimated fair value less costs to sell. At December 31, 2013, the Sendero assets, Pioneer Alaska and the Barnett Shale assets were classified as held for sale and carried as such until their divestitures in March 2014, April 2014 and September 2014, respectively. Beginning in the third quarter of 2014, the Hugoton assets were classified as held for sale until their divestiture in September 2014. At December 31, 2013, the fair value of the Barnett Shale assets was based upon a weighted average calculation that utilized management inputs for both an estimated sales price and a discounted cash flow model for the proved properties using Level 3 assumptions as discussed in the proved oil and gas properties section above, while Sendero and Pioneer Alaska fair values were each based solely on estimated sales prices, less costs to sell. During 2014, the fair value measurements of all assets classified as held for sale were based on their sales prices, less costs to sell. See Note C for additional information regarding the Company's divestitures. The following table presents the fair value adjustments made by the Company during the years ended December 31, 2014 and 2013 related to assets associated with divestitures: Year Ended December 31, 2014 Year Ended December 31, 2013 Classification Estimated Fair Value Less Costs to Sell Fair Value Adjustment Estimated Fair Value Less Costs to Sell Fair Value Adjustment (in millions) Hugoton field Discontinued operations $ 328 $ (34 ) Barnett Shale field Discontinued operations $ 149 $ (174 ) $ 180 $ (190 ) Pioneer Alaska Discontinued operations $ 253 $ (97 ) $ 351 $ (539 ) Sendero Continuing operations $ 31 $ (25 ) Unproved oil and gas properties. During 2015 and 2014, the Company recorded impairment charges of $7 million and $50 million to reduce the carrying value of unproved properties in southeast Colorado (reported in exploration and abandonments in the accompanying consolidated statements of operations). During 2015, the Company impaired the remaining carrying value of its unproved properties in southeast Colorado as a result of the Company no longer planning to develop this acreage and the acreage's limited market value, if any, given the short time period until the leases expire. At December 31, 2014, the Company calculated the estimated fair values of the unproved acreage in southeast Colorado using significant Level 3 assumptions based on average lease bonuses per acre for its prospective acreage. No value was allocated to acreage that the Company did not plan to develop in southeast Colorado. Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (in millions) Current portion of long-term debt $ 448 $ 462 $ — $ — Long-term debt $ 3,207 $ 3,206 $ 2,648 $ 2,938 Current and noncurrent long-term debt includes the Company's credit facility and the Company's senior notes. The fair value of the Company's debt obligations is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy. Credit facility . The fair value of the Company's credit facility is calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rates and (iii) the applicable credit-adjustments. Senior notes . The Company's senior notes represent debt securities that are not actively traded on major exchanges. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges. The Company has other financial instruments consisting primarily of cash equivalents, accounts receivables, prepaid expenses, notes receivable, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations. Concentrations of credit risk. As of December 31, 2015 , the Company's primary concentration of credit risks are the risks associated with collecting receivables (principally accounts receivables and notes receivables) and the risk of a counterparty's failure to perform under derivative contracts owed to the Company. See Note L for information regarding the Company's major customers. With respect to accounts receivables and notes receivables, the Company uses credit and other financial criteria to evaluate the credit standing of the entity obligated to make the payment, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the entity or such other credit support as the Company believes is appropriate. The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note E for additional information regarding the Company's derivative activities and information regarding derivative net assets and liabilities by counterparty.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	NOTE E. Derivative Financial Instruments The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness. Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") WTI oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and actual index prices at which the oil is sold. The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of December 31, 2015 and the weighted average oil prices for those contracts: 2016 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Swap contracts: Volume (Bbl) (a) 35,000 35,000 — — — Price per Bbl $ 59.88 $ 59.88 $ — $ — $ — Collar contracts with short puts: Volume (Bbl) (a) 63,000 68,000 112,000 112,000 34,000 Price per Bbl: Ceiling $ 73.29 $ 72.43 $ 75.94 $ 75.94 $ 70.42 Floor $ 63.04 $ 62.08 $ 65.41 $ 65.41 $ 57.65 Short put $ 43.17 $ 42.94 $ 47.03 $ 47.03 $ 47.65 _______________ (a) During the period from January 1, 2016 through February 16, 2016, the Company converted 25,000 Bbls per day of March through June 2016 collar contracts with short puts with a ceiling price of $71.02 per Bbl, a floor price of $60.00 per Bbl and a short put price of $48.00 per Bbl into new swap contracts covering the same period with a fixed price of $43.54 per Bbl. NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway NGL component product prices. The Company uses derivative contracts to manage the NGL component product price volatility. The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of December 31, 2015 and the weighted average NGL prices for those contracts: 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Propane swap contracts (a): Volume (Bbl) 7,500 7,500 7,500 7,500 Price per Bbl $ 21.57 $ 21.57 $ 21.57 $ 21.57 ____________________ (a) Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas-posted prices. Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("HH") gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold. The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of December 31, 2015 and the weighted average gas prices for those contracts: 2016 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Swap contracts: Volume (MMBtu) 70,000 70,000 70,000 70,000 — Price per MMBtu $ 4.06 $ 4.06 $ 4.06 $ 4.06 $ — Collar contracts with short puts: Volume (MMBtu) 180,000 180,000 180,000 180,000 — Price per MMBtu: Ceiling $ 4.01 $ 4.01 $ 4.01 $ 4.01 $ — Floor $ 3.24 $ 3.24 $ 3.24 $ 3.24 $ — Short put $ 2.78 $ 2.78 $ 2.78 $ 2.78 $ — Basis swap contracts: Gulf Coast basis swap contracts (a) 10,000 10,000 10,000 10,000 — Price differential ($/MMBtu) $ — $ — $ — $ — $ — Mid-Continent index swap volume (a) 15,000 15,000 15,000 15,000 45,000 Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) Permian Basin index swap volume (b) (c) 6,813 — — — — Price differential ($/MMBtu) $ 0.26 $ — $ — $ — $ — ____________________ (a) Represents swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts. (b) Represents swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California. (c) During the period from January 1, 2016 through February 16, 2016, the Company entered into (i) an additional 40,000 MMBtu per day of basis swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California for the November 2016 through March 2017 time period with a fixed price of $0.37 per MMBtu and (ii) an additional 25,000 MMBtu per day of basis swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California for December 2016 with a fixed price of $0.53 per MMBtu. Marketing and basis derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of December 31, 2015 , the Company did not have any marketing derivatives outstanding. Interest rate derivative activities. During 2015, the Company terminated its interest rate derivative contracts for cash proceeds of $3 million . As of December 31, 2015 , the Company did not have any interest rate derivatives outstanding. During the period from January 1, 2016 through February 16, 2016, the Company entered into interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.98 percent on a notional amount of $200 million on December 15, 2017. Tabular disclosure of derivative financial instruments . All of the Company's derivatives are accounted for as non-hedge derivatives as of December 31, 2015 and December 31, 2014 and therefore all changes in the fair values of its derivative contracts are recognized 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 as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following: Fair Value of Derivative Instruments as of December 31, 2015 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 695 $ (1 ) $ 694 Commodity price derivatives Derivatives - noncurrent $ 64 $ — 64 $ 758 Liability Derivatives: Commodity price derivatives Derivatives - current $ 1 $ (1 ) $ — Commodity price derivatives Derivatives - noncurrent $ 1 $ — 1 $ 1 Fair Value of Derivative Instruments as of December 31, 2014 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 579 $ (1 ) $ 578 Commodity price derivatives Derivatives - noncurrent $ 182 $ (1 ) 181 $ 759 Liability Derivatives: Commodity price derivatives Derivatives - current $ 1 $ (1 ) $ — Interest rate derivatives Derivatives - current $ 3 $ — 3 Commodity price derivatives Derivatives - noncurrent $ 3 $ (1 ) 2 $ 5 The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recognized in Earnings on Derivatives Amount of Gain/(Loss) Recognized in Earnings on Derivatives Year Ended December 31, 2015 2014 2013 (in millions) Commodity price derivatives Derivative gains, net $ 873 $ 697 $ (6 ) Interest rate derivatives Derivative gains, net 6 15 10 Total $ 879 $ 712 $ 4 Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures. The following table provides the Company's net derivative assets by counterparty as of December 31, 2015 : Net Assets (in millions) Merrill Lynch $ 138 Citibank, N.A. 109 BMO Financial Group 108 Societe Generale 105 J. Aron & Company 81 Morgan Stanley 53 Wells Fargo Bank, N.A. 51 JP Morgan Chase 49 Macquarie Bank 34 Den Norske Bank 16 Nextera Energy 9 Toronto Dominion 4 Total $ 757

Exploratory Well Costs

Exploratory Well Costs	12 Months Ended
	Dec. 31, 2015
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs	NOTE F. Exploratory Well Costs The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense. The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Beginning capitalized exploratory well costs $ 305 $ 159 $ 213 Additions to exploratory well costs pending the determination of proved reserves 1,178 1,860 1,220 Reclassification due to determination of proved reserves (1,160 ) (1,628 ) (1,045 ) Divestitures — (47 ) (93 ) Impairment of properties — (13 ) (87 ) Exploratory well costs charged to exploration and abandonment expense (a) (17 ) (26 ) (49 ) Ending capitalized exploratory well costs $ 306 $ 305 $ 159 _______________ (a) Includes exploration and abandonment expense of $43 million in 2013 that is included in discontinued operations in the accompanying consolidated statements of operations. The following table provides an aging, as of December 31, 2015 , 2014 and 2013 of capitalized exploratory 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: As of December 31, 2015 2014 2013 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 303 $ 305 $ 116 More than one year 3 — 43 $ 306 $ 305 $ 159 Number of projects with exploratory well costs that have been suspended for a period greater than one year 1 — 1 The project with exploratory well costs that have been suspended for a period greater than one year at December 31, 2015 is scheduled to be completed during 2016. The $43 million of suspended well costs that were suspended for a period greater than one year at December 31, 2013 related to Pioneer Alaska, which was sold in April 2014. See Note C for additional information on the sale of Pioneer Alaska.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	NOTE G. Long-term Debt and Interest Expense Long-term debt, including the effects of issuance costs, issuance discounts and net deferred fair value hedge losses, consisted of the following components at December 31, 2015 and 2014 : December 31, 2015 2014 (in millions) Outstanding debt principal balances: 5.875% senior notes due 2016 (a) $ 455 $ 455 6.65% senior notes due 2017 485 485 6.875% senior notes due 2018 450 450 7.500% senior notes due 2020 450 450 3.45% senior notes due 2021 500 — 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 — 7.20% senior notes due 2028 250 250 3,690 2,690 Issuance costs and discounts (35 ) (41 ) Net deferred fair value hedge losses — (1 ) Long-term debt 3,655 2,648 Less current portion of long-term debt (a) 448 — Long-term debt $ 3,207 $ 2,648 ______________________________ (a) These notes, net of $7 million of unamortized issuance costs, issuance discounts and deferred fair value hedge losses, are classified as current in the accompanying consolidated balance sheets. Credit facility. During August 2015, the Company entered into a Second Amendment to its Second Amended and Restated 5-year Revolving Credit Agreement ("Credit Facility") with a syndicate of financial institutions, primarily to extend the maturity of the credit facility from December 2017 to August 2020 while maintaining aggregate loan commitments of $1.5 billion . The Company accounted for the entry into the Credit Facility as a modification of the prior agreement and capitalized the debt issuance costs along with those unamortized issuance costs that remained from the issuance of the prior agreement. As of December 31, 2015 , the Company had no outstanding borrowings 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, which is currently 0.5 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 1.50 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 0.20 percent ). Borrowings under the Credit Facility are general unsecured obligations. The Credit Facility requires the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed .60 to 1.0. As of December 31, 2015 , the Company was in compliance with all of its debt covenants. Senior notes. During December 2015, the Company issued $500 million of 3.45% Senior Notes due 2021 and $500 million of 4.45% Senior Notes due 2026 and received combined proceeds, net of $9 million of offering costs and discounts, of $991 million . The Company's 5.875% senior notes (the "5.875% Senior Notes"), with an outstanding debt principal balance of $455 million, are due to mature in July 2016. The Company intends to fund the payments due at maturity of the 5.875% Senior Notes with cash on hand. As such, the 5.875% Senior Notes are classified as current in the accompanying consolidated balance sheets. The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable semiannually. Convertible senior notes. As of December 31, 2012, the Company had $480 million of Convertible Senior Notes outstanding. During December 2012 and March 2013, the Company's stock price met the price threshold that caused the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $1 million in principal and interest to redeem all Convertible Senior Notes that remained outstanding. For the year ended December 31, 2013 the Company recorded $9 million of interest expense relating to the Convertible Senior Notes, which had an effective interest rate of 6.75 percent . Principal maturities. Principal maturities of long-term debt at December 31, 2015 , are as follows (in millions): 2016 $ 455 2017 $ 485 2018 $ 450 2019 $ — 2020 $ 450 Thereafter $ 1,850 Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Cash payments for interest $ 148 $ 193 $ 183 Amortization of issuance discounts 13 12 12 Amortization of capitalized loan fees 5 5 5 Net changes in accruals 25 (22 ) (6 ) Interest incurred 191 188 194 Less capitalized interest (4 ) (4 ) (10 ) Total interest expense $ 187 $ 184 $ 184

Incentive Plans

Incentive Plans	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Compensation and Employee Benefit Plans [Text Block]	NOTE H. Incentive Plans Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of directors (the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company's matching contributions were $3 million , $3 million and $3 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. 401(k) plan. The Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's base compensation (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four -year period that begins with the participant's date of hire. During the years ended December 31, 2015 , 2014 and 2013 , the Company recognized compensation expense of $31 million , $33 million and $30 million , respectively, as a result of Matching Contributions. Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense ratably over the vesting periods of the Company's stock-based compensation awards using the awards' fair value. The Company maintains two plans providing for stock-based compensation: the Long-Term Incentive Plan ("LTIP") and the Employee Stock Purchase Plan ("ESPP"). In December 2015, the Company terminated the Pioneer 2008 PSE Employee Long-Term Incentive Plan ("PSE LTIP"). The PSE LTIP was adopted by Pioneer Southwest in May 2008. The plan, along with all of Pioneer Southwest's obligations under outstanding awards, was assumed by the Company in connection with the Company's acquisition of all outstanding common units of Pioneer Southwest not owned by the Company in December 2013, at which time the plan's name was changed. The only outstanding awards under the PSE LTIP at the time of the acquisition were phantom units of Pioneer Southwest, all of which were converted into restricted stock units of the Company, and no awards have been granted under the PSE LTIP since the Company's assumption of the plan. The Company terminated the plan as there was no intent to issue additional awards under the plan. At the time of termination of the plan, there were 7,495 restricted units outstanding, all of which are scheduled to vest on February 20, 2016. These awards were originally granted on February 20, 2013. Long-Term Incentive Plan. The LTIP provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market. The following table shows the number of shares available for issuance pursuant to awards under the LTIP at December 31, 2015 : Approved and authorized awards 9,100,000 Awards issued after May 3, 2006 (7,017,999 ) Awards available for future grant 2,082,001 Employee Stock Purchase Plan. The ESPP allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing sales price is lower. The following table shows the number of shares available for issuance under the ESPP at December 31, 2015 : Approved and authorized shares 1,250,000 Shares issued (833,078 ) Shares available for future issuance 416,922 The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award and the associated income tax benefit for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Restricted stock-Equity Awards $ 70 $ 65 $ 57 Restricted stock-Liability Awards 22 28 40 Stock options (a) — 2 3 Performance unit awards 18 13 9 ESPP 2 2 2 Other — — 1 Total $ 112 $ 110 $ 112 Income tax benefit $ 34 $ 33 $ 36 _____________________ (a) Cash proceeds received from stock option exercises during 2014 and 2013 amounted to $6 million and $5 million , respectively. There were no stock option exercises during 2015 . As of December 31, 2015 , there was $108 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $17 million attributable to Liability Awards. The stock-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. Restricted stock awards. During 2015 , the Company awarded 603,169 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 161,692 shares or units representing Liability Awards). The Company's issued shares, as reflected in the accompanying consolidated balance sheet as of December 31, 2015 , do not include 128,002 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights. The following table reflects the restricted stock award activity for the year ended December 31, 2015 : Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 1,233,539 $ 140.57 328,087 Shares granted 441,477 $ 153.55 161,692 Shares forfeited (46,429 ) $ 155.52 (33,082 ) Shares vested (546,937 ) $ 138.76 (185,666 ) Outstanding at end of year 1,081,650 $ 151.50 271,031 The weighted average grant-date fair value of restricted stock equity awards awarded during 2015 , 2014 and 2013 was $153.55 , $184.39 and $134.17 , respectively. The fair value of shares for which restrictions lapsed during 2015 , 2014 and 2013 was $66 million , $88 million and $69 million , respectively, based on the market price on the vesting date. As of December 31, 2015 and 2014 , accounts payable – due to affiliates in the accompanying consolidated balance sheets includes $16 million and $23 million of liabilities attributable to the Liability Awards, representing the fair value of the earned, but unvested, portion of the outstanding awards as of that date. The fair value of Liability Awards for which restrictions lapsed during 2015 , 2014 and 2013 was $23 million , $38 million and $26 million respectively, based on the market price on the vesting date. Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock with an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Option awards have a ten -year contract life. The expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a seven -year average dividend yield. A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2015 is presented below: Number of Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Life Aggregate Intrinsic Value (in years) (in millions) Outstanding at beginning of year 199,058 $ 77.51 Options exercised — $ — Outstanding at end of year 199,058 $ 77.51 4.96 $ 10 Exercisable at end of year 199,058 $ 77.51 4.96 $ 10 The Company has not granted stock options since February 2012. There were no options exercised during 2015 . The intrinsic value of options exercised during 2014 and 2013 was $12 million and $21 million , respectively, based on the difference between the market price at the exercise date and the option exercise price. Performance unit awards. During 2015 , 2014 and 2013 , the Company awarded performance units to certain of the Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34 -month service period. The grant-date fair values per unit of the 2015 , 2014 and 2013 performance unit awards were $222.33 , $232.20 and $189.23 , respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as stock-based compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2015 , 2014 and 2013 : 2015 2014 2013 Risk-free interest rate 1.03% 0.62% 0.40% Range of volatilities 26.1 % - 41.3% 29.0 % - 41.5% 30.4 % - 42.9% The following table summarizes the performance unit activity for the year ended December 31, 2015 : Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 154,733 $ 207.88 Units granted 82,431 $ 222.33 Units forfeited — $ — Units vested (b) (88,617 ) $ 189.71 Ending performance unit awards 148,547 $ 226.74 _____________________ (a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. (b) Of the 88,617 units that vested during 2015, 87,551 units vested according to the scheduled timing of the associated award and 1,066 units, which were originally scheduled to vest in 2016 and 2017, vested upon retirement of the officer to whom the performance unit awards were granted. On December 31, 2015 , the service period lapsed on 88,374 performance unit awards that earned 1.5 shares for each vested award, representing 132,566 aggregate shares of common stock issued on January 4, 2016. The vested performance units that earned 1.5 shares for each vested award included 87,551 units vested in the current year and 823 units that vested in 2014 upon the retirement of the officer to whom the performance unit awards were granted. The fair value of shares for which restrictions lapsed during 2015 , 2014 and 2013 was $17 million , $13 million and $19 million , respectively, based on the market price on the vesting date.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	NOTE I. Asset Retirement Obligations The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Beginning asset retirement obligations $ 189 $ 194 $ 198 Obligations assumed in acquisitions — 6 — New wells placed on production 4 5 6 Changes in estimates (a) 103 7 8 Disposition of wells — (14 ) (16 ) Obligations settled (23 ) (21 ) (15 ) Accretion of discount on continuing operations 12 12 12 Accretion of discount on discontinued operations — — 1 Ending asset retirement obligations $ 285 $ 189 $ 194 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The increase in 2015 is primarily due to the forecasted timing of abandoning the Company's oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company's producing wells. As of December 31, 2015 and 2014 , the current portions of the Company's asset retirement obligations were $40 million and $28 million , respectively.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	NOTE J. Commitments and Contingencies Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $35 million . Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation. Legal actions. The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. These retention and indemnification arrangements were undertaken by the Company with respect to some or all of such pre-closing matters in connection with the sale of its Argentine assets in 2006, the sale of its Canadian assets in 2007, the sale of Pioneer Tunisia in February 2011, the sale of Pioneer South Africa in August 2012, the sales of Pioneer Alaska and the Hugoton and Barnett Shale assets in 2014 and the sale of the Company's ownership interest in EFS Midstream in 2015, as well as in connection with sales of joint interests. 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. Drilling commitments. The Company's principal drilling commitments are related to drilling rig contracts that require the Company to pay day rates for contracted drilling rigs over their contractual term. In addition, the Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company recognizes its drilling commitments in the periods in which the rig services are performed or the well is drilled. The Company's future minimum drilling commitments at December 31, 2015 include only drilling rig obligations that are expected to be paid as follows (in millions): 2016 $ 179 2017 $ 110 2018 $ 64 2019 $ 10 2020 $ — Thereafter $ — Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the years ended December 31, 2015 , 2014 and 2013 was $ 58 million , $66 million and $58 million , respectively. These payments include $ 9 million and $10 million associated with discontinued operations for the years ended December 31, 2014 and 2013, respectively, and are included in the loss from discontinued operations, net of tax, in the accompanying consolidated statements of operations for each respective year. Future minimum lease commitments under noncancelable operating leases at December 31, 2015 are as follows (in millions): 2016 $ 24 2017 $ 23 2018 $ 21 2019 $ 21 2020 $ 17 Thereafter $ 15 Future minimum lease commitments include $7 million for the Company's lease obligations related to the Denver, Colorado office, which was closed during 2015. The Company has recognized the remaining obligation, net of anticipated sublease income, of $3 million in restructuring expense for the year ended December 31, 2015. Since the Company is still responsible for the cash payment of the entire obligation before taking into account anticipated sublease income, the table above includes the gross amount of future lease payments associated with the Denver office. See Note B for further information on the Company's restructuring expense. Firm purchase, gathering, processing, transportation and fractionation commitments. The Company from time to time enters into, and as of December 31, 2015 was a party to, take-or-pay agreements, which include contractual commitments to purchase sand and water for use in the Company's drilling operations and contractual commitments with midstream service companies and pipeline carriers for future gathering, processing, transportation and fractionation. These commitments are normal and customary for the Company's business activities. Future minimum purchase, gathering, processing, transportation and fractionation commitments at December 31, 2015 are as follows (in millions): 2016 $ 451 2017 $ 479 2018 $ 476 2019 $ 467 2020 $ 465 Thereafter $ 1,145 Certain future minimum gathering, processing, transportation and fractionation fees are based upon rates and tariffs that are subject to change over the lives of the commitments. The above commitments include demand fees associated with volume delivery commitments. If the Company does not expect to be able to fulfill its short-term and long-term delivery obligations from projected production of available reserves, the Company expects to purchase third party volumes, where applicable, to satisfy its commitment assuming it is economic to do so; otherwise, it will pay the demand fees associated with any commitment shortfalls.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	NOTE K. Related Party Transactions Transactions with affiliated partnerships. Prior to December 2014, the Company, through a wholly-owned subsidiary, served as operator of properties in which it and its affiliated partnerships had an interest. The Company received lease operating and supervision charges in accordance with standard industry operating agreements related to the operation of the properties in which it and its affiliated partnerships had an interest and other fees related to the administration of the affiliated partnerships. For each of the years ended December 31, 2014 and 2013 , the Company received $3 million associated with these fees. In December 2014, the Company acquired the remaining limited partner interests in the affiliated partnerships and caused the partnerships to be merged with and into the Company. Prior to the acquisition, the Company proportionately consolidated the affiliated partnerships. Transactions with EFS Midstream. Prior to July 2015, the Company, through a wholly-owned subsidiary, owned a noncontrolling interest in its unconsolidated affiliate, EFS Midstream. In July 2015, the Company completed the sale of its interest in EFS Midstream to an unaffiliated third party. Prior to its sale in July 2015 and for the years ended December 31, 2014 and 2013, the Company received nil , $50 million and $25 million , respectively, in distributions from EFS Midstream. Prior to July 2015, the Company also (i) provided certain services as the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) contracted for services from EFS Midstream under a Hydrocarbon Gathering and Handling Agreement (the "HGH Agreement"). Master Services Agreement. The terms of the Master Services Agreement provided that the Company would perform certain manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to expenses incurred by employees whose time was substantially dedicated to EFS Midstream's business. During 2015 , 2014 and 2013 , the Company received $2 million , $3 million and $3 million of fixed payments and $9 million , $18 million and $16 million of variable payments, respectively, from EFS Midstream. During 2013, the Company purchased other plant and equipment assets from EFS Midstream for a total of $3 million . Hydrocarbon Gathering and Handling Agreement. Under the terms of the HGH Agreement, EFS Midstream was obligated to construct certain equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated by the Company. The HGH Agreement obligated the Company to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement, the Company paid EFS Midstream $54 million (prior to its sale), $103 million and $81 million of gathering and treating fees during 2015 , 2014 and 2013 , respectively. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements of operations.

Major Customer

Major Customer	12 Months Ended
	Dec. 31, 2015
Concentration Risks, Types, No Concentration Percentage [Abstract]
Major Customers	NOTE L. Major Customers The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas production revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2015 : Year Ended December 31, 2015 2014 2013 Plains Marketing LP 22 % 29 % 28 % Occidental Energy Marketing Inc. 18 % 16 % 13 % Vitol, Inc. 18 % 9 % 5 % Enterprise Products Partners L.P. 12 % 13 % 13 % The loss of any of these significant purchasers could have a material adverse effect on the ability of the Company to sell its oil and gas production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price and to satisfy unused pipeline capacity commitments. The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas revenues from sales of commodities purchased from third parties in at least one of the three years ended December 31, 2015 : Year Ended December 31, 2015 2014 2013 Valero Marketing and Supply Company 37 % 61 % 51 % Occidental Energy Marketing Inc. 18 % — % 1 % Plains Marketing LP 18 % — % — % EDF Trading North America LLC 4 % 9 % 20 % The Company believes that the loss of any of these purchasers would not have an adverse effect on the ability of the Company to sell commodities it purchases from third parties.

Interest And Other Income

Interest And Other Income	12 Months Ended
	Dec. 31, 2015
Interest and Other Income [Abstract]
Interest And Other Income	NOTE M. Interest and Other Income The following table provides the components of the Company's interest and other income during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Equity interest in income of EFS Midstream (a) $ 5 $ 13 $ 7 Deferred compensation plan income 4 3 6 Interest income 3 — — Other income 10 10 10 Total interest and other income $ 22 $ 26 $ 23 ______________________ (a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. See Note C for additional information on the Company's sale of EFS Midstream.

Other Expense

Other Expense	12 Months Ended
	Dec. 31, 2015
Other Expense [Abstract]
Other Expense	NOTE N. Other Expense The following table provides the components of the Company's other expense during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Idle drilling and well service equipment charges (a) $ 92 $ 7 $ 10 Impairment of inventory and other property and equipment (b) 86 8 62 Transportation commitment charges (c) 53 46 39 Loss from vertical integration services (d) 34 16 5 Restructuring charges (e) 23 — — Contingency and environmental accrual adjustments — — 9 Other 27 29 18 Total other expense $ 315 $ 106 $ 143 ____________________ (a) Primarily represents expenses attributable to idle drilling rig fees which are not chargeable to joint operations. (b) Primarily represents charges of $71 million , $8 million and $36 million to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2015 , 2014 and 2013, respectively, and a charge of $25 million for the year ended December 31, 2013 to reduce the carrying value of Sendero to its estimated fair value. See Notes C and D for additional information on the fair value of material and supplies inventory and Sendero, respectively. (c) Primarily represents firm transportation payments on excess pipeline capacity commitments. (d) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2015 , 2014 and 2013 , these net losses include $298 million , $374 million and $285 million of gross vertical integration revenues, respectively, and $332 million , $390 million and $290 million of total vertical integration costs and expenses and elimination of revenues associated with intercompany transactions, respectively. (e) Represents restructuring costs associated with the Company's restructuring of its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. See Note B for additional information on the restructuring charges.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	NOTE O. Income Taxes The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. The Company made current and estimated tax payments of $43 million , $22 million and $12 million (net of tax refunds) during 2015 , 2014 and 2013 , respectively. The Company continually assesses 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 and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the United States federal, state, local and foreign tax jurisdictions will be utilized prior to their expiration. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. During 2014, the Company recognized a $21 million tax benefit resulting from the resolution of a tax uncertainty related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica. The Company does not have any unrecognized tax benefits as of December 31, 2015 . With respect to income taxes, the Company's policy is to account for interest charges as interest expense and any penalties as other expense in the accompanying consolidated statements of operations. The Company files income tax returns in the United States federal jurisdiction, and various state and foreign jurisdictions. As of December 31, 2015 , there are no proposed adjustments or uncertain positions in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The Company's earliest open years in its key jurisdictions are as follows: U.S. federal 2014 Various U.S. states 2010 South Africa 2010 The Company's income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Income tax (provision) benefit from continuing operations $ 155 $ (556 ) $ 213 Income tax benefit from discontinued operations $ 2 $ 60 $ 249 Changes in equity: Excess tax benefit related to stock-based compensation $ 7 $ 19 $ 18 Tax benefit attributable to conversion of 2.875% senior convertible notes $ — $ — $ 38 Tax benefit attributable to 2013 merger with Pioneer Southwest $ — $ — $ 200 The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Current: U.S. federal $ (22 ) $ (3 ) $ (11 ) U.S. state (1 ) (1 ) — (23 ) (4 ) (11 ) Deferred: U.S. federal 165 (537 ) 208 U.S. state 13 (15 ) 16 178 (552 ) 224 Income tax (provision) benefit from continuing operations $ 155 $ (556 ) $ 213 Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income (loss) from continuing operations are as follows for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions, except percentages) Income (loss) from continuing operations before income taxes $ (421 ) $ 1,597 $ (574 ) Less: Net income attributable to noncontrolling interests — — (39 ) Income (loss) from continuing operations attributable to common stockholders before income taxes (421 ) 1,597 (613 ) Federal statutory income tax rate 35 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate 147 (559 ) 215 State income tax (provision) benefit (net of federal tax) 8 (10 ) 10 Premier Silica benefit — 21 — Other — (8 ) (12 ) Income tax (provision) benefit from continuing operations $ 155 $ (556 ) $ 213 Effective income tax rate, excluding net income attributable to the noncontrolling interests 37 % 35 % 35 % The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2015 and 2014 : December 31, 2015 2014 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 441 $ 330 Asset retirement obligations 102 68 Incentive plans 75 71 Other 102 74 Total deferred tax assets 720 543 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (1,997 ) (1,881 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (227 ) (251 ) Net deferred hedge gains (272 ) (280 ) Other — (95 ) Total deferred tax liabilities (2,496 ) (2,507 ) Net deferred tax liability $ (1,776 ) $ (1,964 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2015 consist of $1.2 billion of U.S. federal NOLs which expire primarily between 2032 and 2035 and $132 million of Colorado NOLs which expire between 2028 and 2034.

Net Income (Loss) Per Share Att

Net Income (Loss) Per Share Attributable To Common Stockholders	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Net Income (Loss) Per Share Attributable To Common Stockholders	NOTE P. Net Income Per Share Attributable To Common Stockholders In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income (loss) per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive 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 in which 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 net loss per share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Income (loss) from continuing operations $ (266 ) $ 1,041 $ (400 ) Participating basic earnings (a) — (10 ) — Basic and diluted net income (loss) from continuing operations (266 ) 1,031 (400 ) Basic and diluted net loss from discontinued operations (7 ) (111 ) (438 ) Basic and diluted net income (loss) attributable to common stockholders $ (273 ) $ 920 $ (838 ) ______________________ (a) Unvested restricted stock awards and Pioneer Southwest phantom unit awards (prior to the December 2013 Pioneer Southwest merger) represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so. Basic and diluted weighted average common shares outstanding were 149 million , 144 million and 136 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	NOTE Q. Subsequent Events Issuance of Common Stock. During the first quarter of 2016, the Company issued 13.8 million shares of its common stock and received cash proceeds of $1.6 billion , net of associated underwriting and offering expenses. Pioneer Pumping Services. During February 2016, the Company announced that it is relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. The Company expects to relocate the majority of its pressure pumping employees from South Texas to Midland, Texas. This initiative is expected to be substantially completed by the end of the second quarter of 2016. The Company estimates that it will incur $10 million to $20 million of restructuring costs in connection with this plan, primarily made up of employee relocation and severance payments and other related costs.

Summary Of Significant Accoun25

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles Of Consolidation	Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the 2014 and 2013 financial statement and footnote amounts in order to conform them to the 2015 presentations.
Reclassification, Policy [Policy Text Block]	Certain reclassifications have been made to the 2014 and 2013 financial statement and footnote amounts in order to conform them to the 2015 presentations.
Use Of Estimates In The Preparation Of Financial Statements	Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.
Cash Equivalents	Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.
Accounts Receivable	Accounts receivable. As of December 31, 2015 and 2014 , the Company had accounts receivable – trade, net of allowances for bad debts, of $384 million and $436 million , respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. As of both December 31, 2015 and 2014 , the Company's allowances for doubtful accounts totaled $1 million . The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable 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 Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.
Inventories	Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, natural gas liquids ("NGLs") and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. The following table presents the Company's materials and supplies and commodity inventories as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in millions) Materials and supplies (a) $ 132 $ 223 Commodities 23 18 $ 155 $ 241 ____________________ (a) As of December 31, 2015 and 2014 , the Company's materials and supplies inventories were net of valuation allowances of $78 million and $22 million , respectively. See Note D for additional information regarding inventory impairments.
Oil And Gas Properties	Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) The well has found a sufficient quantity of reserves to justify its completion as a producing well; and (ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs. The Company owns interests in seven gas processing plants and eight treating facilities. The Company is the operator of one of the gas processing plants and all eight of the treating facilities. Six of the gas processing plants are operated by third parties and six of the treating facilities are not currently being used. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities in continuing operations for the years ended December 31, 2015 , 2014 and 2013 were $39 million , $56 million and $53 million , respectively. Third party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $27 million , $24 million and $21 million . The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's impairment of proved oil and gas properties. Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time.
Goodwill	Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but 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 to the impaired value with a corresponding charge to earnings in the period in which it is determined to be impaired. During the third quarter of 2015 , the Company performed a quantitative assessment of goodwill and determined that there was no impairment. The Company reevaluated this assessment during the fourth quarter of 2015 due to reductions in (i) management's longer-term commodity price outlooks ("Management's Price Outlooks") and (ii) the Company's common stock price. Based upon the results of this qualitative assessment, the Company determined that it was more likely than not that the Company's goodwill was not impaired.
Other Property And Equipment, Net	Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2015 and 2014 , respectively, the net carrying value of other property and equipment consisted of the following: As of December 31, 2015 (a) 2014 (a) (in millions) Proved and unproved sand properties (b) $ 473 $ 469 Land and buildings 468 440 Equipment and rigs (c) 287 338 Water infrastructure (d) 180 10 Vehicles 21 35 Furniture and fixtures 67 70 Leasehold improvements 27 29 $ 1,523 $ 1,391 ____________________ (a) At December 31, 2015 and 2014 , other property and equipment was net of accumulated depreciation of $711 million and $563 million , respectively. (b) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. (c) Includes well servicing equipment and rigs and fracture stimulation equipment that are owned by wholly-owned subsidiaries that provide pumping and well services on Company-operated properties. As of December 31, 2015 , the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. (d) Includes water supply wells and pipeline infrastructure costs. The primary purposes of the Company's sand mines and pumping and well services operations are to accommodate the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. All intercompany gains or losses of the Company's sand mines and pumping and well services operations are eliminated. The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years. Equipment and rigs, vehicles, and furniture and fixtures are generally depreciated over two to 15 years. Water infrastructure is generally depreciated over 10 to 50 years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.
Investment In Unconsolidated Affiliate	Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party. In July 2015, the Company sold its remaining 50.1 percent interest in EFS Midstream to an unaffiliated third party. See Note C for additional information regarding the Company's divestitures. Prior to the sale, the Company did not have control of EFS Midstream. Consequently, the Company accounted for this 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 member interests sold and the investor's share of the investee's net losses. The Company's equity interest in the net income or loss of EFS Midstream (prior to its sale) was recorded in interest and other income, net of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income of EFS Midstream for the years ended December 31, 2015 , 2014 and 2013 .
Asset Retirement Obligations	Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated. 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 and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations.
Treasury Stock	Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
Noncontrolling Interest In Consolidated Subsidiaries	Noncontrolling interest in consolidated subsidiaries. The Company owns the majority interests in certain subsidiaries with operations in the United States. Prior to December 17, 2013, the Company owned a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest") and consolidated the financial position, results of operations and cash flows of Pioneer Southwest with those of Pioneer. Pioneer Southwest owned proved and unproved oil and gas properties in the Spraberry field in the Permian Basin of West Texas. On December 17, 2013, the holders of a majority of the outstanding common units of Pioneer Southwest approved an amended agreement and plan of merger, pursuant to which (i) all of the then outstanding common units of Pioneer Southwest were canceled and converted into the right to receive 0.2325 of a share of common stock of the Company and (ii) Pioneer Southwest became a wholly-owned subsidiary of the Company. The changes in the Company's ownership of Pioneer Southwest were accounted for by eliminating the noncontrolling interest attributable to Pioneer Southwest. See Note C for additional information about Pioneer Southwest and the amended agreement and plan of merger. Noncontrolling interests in the net assets of consolidated subsidiaries totaled $7 million and $8 million as of December 31, 2015 and 2014 , respectively. For the years ended December 31, 2015 and December 31, 2014 , the Company recorded nominal net losses attributable to the noncontrolling interests, as compared to $39 million of net income attributable to the noncontrolling interests for the years ended December 31, 2013 . The decrease in income attributable to noncontrolling interests for the years ended December 31, 2015 and 2014 , as compared 2013 , is due to the Company's acquisition of all of the outstanding common units of Pioneer Southwest not owned by the Company in December 2013. The Company records transfers of any gains or losses, net of taxes, from noncontrolling interests in consolidated subsidiaries to additional paid in capital in an amount proportionate to the ownership of those noncontrolling interests after giving effect to the purchase or sale of common units. There were no transfers of gains or losses, net of tax, from noncontrolling interest to additional paid in capital during 2015. The effect of transfers of gains or losses, net of tax, from noncontrolling interest to additional paid in capital was a decrease of $1 million in 2014 associated with Pioneer Southwest merger transaction costs and an increase of $365 million in 2013, comprised of (i) an increase of $169 million to record the acquisition of noncontrolling interest of Pioneer Southwest, (ii) an increase of $200 million to recognize deferred taxes associated with the Pioneer Southwest acquisition and (iii) a decrease of $4 million associated with Pioneer Southwest merger transaction costs.
Revenue Recognition	Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2015 or 2014 . The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate ("WTI") oil sales to a Gulf Coast market price and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N for further information on transportation commitment charges.
Derivatives And Hedging	Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. 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. See Note E for additional information about the Company's derivative instruments.
Environmental	Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.
Stock-Based Compensation	Stock-based compensation. Stock-based compensation expense is being recognized on restricted stock, restricted stock units, performance units and stock option awards that are expected to be settled in the Company's common stock ("Equity Awards") 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 or modification, as applicable. Stock-based compensation awards generally vest over a period of three years. The amount of stock-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date. Stock-based compensation liability awards ("Liability Awards") are restricted stock awards that are expected to be settled in cash on their vesting dates, rather than in common stock. Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value 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 vested portions of the awards are recorded as increases or decreases to stock-based compensation expense. 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 to measure the fair value of Equity Awards and Liability Awards, (iii) the closing stock price on the balance sheet date to measure the fair value of the vested portions of Liability Awards and (iv) the Monte Carlo simulation method to measure the fair value of performance unit awards.
Segment Reporting	Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.
Assets Held for Sale and Discontinued Operations	Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell. In addition, after determining that held for sale criteria has been met, the Company considers whether the assets held for sale meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of tax in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional information about the Company's divestitures.
New Accounting Pronouncements	New accounting pronouncements. Recently Adopted Accounting Pronouncements In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, "Balance Sheet Classification of Deferred Taxes." ASU 2015-17 requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is required to be adopted by all public companies for all annual and interim reporting periods beginning after December 15, 2016. Early adoption of this standard was permitted and the Company elected to adopt this standard, on a retrospective basis, during the fourth quarter of 2015. The adoption of ASU 2015-17 only affects the presentation of the Company's accompanying consolidated balance sheets and related financial statement disclosure in Note O. In conjunction with the adoption of ASU 2015-17, the December 31, 2014 consolidated balance sheet has been restated to reclassify $161 million of current deferred income tax liabilities to noncurrent deferred tax liabilities. In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs." ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to ASU 2015-03, debt issuance costs were required to be recognized as deferred charges and recorded as assets. ASU 2015-03 is required to be adopted by all public companies for all annual and interim reporting periods beginning after December 15, 2015. Early adoption of this standard was permitted and the Company elected to adopt this standard, on a retrospective basis, during the fourth quarter of 2015. The adoption of ASU 2015-03 only affects the presentation of the Company's accompanying consolidated balance sheets and related financial statement disclosures in Note G. In conjunction with the adoption of ASU 2015-03, the December 31, 2014 consolidated balance sheet has been restated to reclassify $17 million of debt issuance costs previously presented as part of other assets to be included as part of long-term debt. In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 restricts the presentation of discontinued operations to business circumstances when the disposal of business operations represents a strategic shift that has or will have a major effect on an entity's operating and financial results. The new guidance also expands the required disclosures for entities that have assets held for sale but do not meet the new definition of discontinued operations. The Company prospectively adopted this standard effective January 1, 2015. The adoption of this standard did not have a material impact on the Company's accompanying consolidated balance sheets or related disclosures as there was not a change to the recognition of assets previously recorded to discontinued operations and the Company did not have any assets available for sale at the time of adoption. New Accounting Pronouncements not adopted as of December 31, 2015 In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements. In July 2015, the FASB issued ASU 2015-11, "Simplifying the Measurement of Inventory." ASU 2015-11 requires an entity to measure inventory at the lower of cost or net realizable value rather than lower of cost or market as previously required by GAAP. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. This update should be applied prospectively with early application permitted. The Company is evaluating the new guidance and does not expect the standard to have a material impact on its consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to annual reports beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

Net IncomePer Share Attributabl

Net IncomePer Share Attributable To Common Stockholders Net Income Per Share Attributable to Common Stockholders (Policies)	12 Months Ended
	Dec. 31, 2015
Net Income Per Share Attributable to Common Stockholders [Abstract]
Earnings Per Share, Policy [Policy Text Block]	In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income (loss) per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive 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 in which 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 net loss per share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding.

Summary Of Significant Accoun27

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Schedule of Inventory, Current [Table Text Block]	The following table presents the Company's materials and supplies and commodity inventories as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in millions) Materials and supplies (a) $ 132 $ 223 Commodities 23 18 $ 155 $ 241 ____________________ (a) As of December 31, 2015 and 2014 , the Company's materials and supplies inventories were net of valuation allowances of $78 million and $22 million , respectively. See Note D for additional information regarding inventory impairments.
Other Property Plant and Equipment [Table Text Block]	At December 31, 2015 and 2014 , respectively, the net carrying value of other property and equipment consisted of the following: As of December 31, 2015 (a) 2014 (a) (in millions) Proved and unproved sand properties (b) $ 473 $ 469 Land and buildings 468 440 Equipment and rigs (c) 287 338 Water infrastructure (d) 180 10 Vehicles 21 35 Furniture and fixtures 67 70 Leasehold improvements 27 29 $ 1,523 $ 1,391 ____________________ (a) At December 31, 2015 and 2014 , other property and equipment was net of accumulated depreciation of $711 million and $563 million , respectively. (b) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. (c) Includes well servicing equipment and rigs and fracture stimulation equipment that are owned by wholly-owned subsidiaries that provide pumping and well services on Company-operated properties. As of December 31, 2015 , the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. (d) Includes water supply wells and pipeline infrastructure costs.

Acquisitions and Divestitures A

Acquisitions and Divestitures Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Acquisitions and Divestitures [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]	The following table represents the components of the Company's discontinued operations for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Revenues and other income (a) $ 1 $ 238 $ 376 Costs and expenses (b) 10 409 1,063 Loss from discontinued operations before income taxes (9 ) (171 ) (687 ) Current tax provision (1 ) — (6 ) Deferred tax benefit 3 60 255 Loss from discontinued operations, net of tax $ (7 ) $ (111 ) $ (438 ) ____________________ (a) Revenues and other income for the years ended December 31, 2014 and 2013 were primarily comprised of oil and gas revenues of $198 million and $329 million , respectively. (b) Costs and expenses during 2015 were primarily related to an arbitration award associated with plugging and abandonment obligations for two Gulf of Mexico wells from which Pioneer withdrew in 2009. The Company incurred noncash impairment charges of $305 million and $729 million during the years ended December 31, 2014 and 2013, respectively, on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 and 2013 also included oil and gas production costs of $60 million and $117 million , respectively. See Note D for additional information regarding the noncash impairment charges related to the Hugoton assets, the Barnett Shale assets and Pioneer Alaska.

Disclosures About Fair Value 29

Disclosures About Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis	The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 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 December 31, 2015 (in millions) Assets: Commodity derivatives $ — $ 758 $ — $ 758 Deferred compensation plan assets 73 — — 73 Total assets 73 758 — 831 Liabilities: Commodity derivatives — 1 — 1 Total liabilities — 1 — 1 Total recurring fair value measurements $ 73 $ 757 $ — $ 830 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Fair Value at December 31, 2014 (in millions) Assets: Commodity derivatives $ — $ 759 $ — $ 759 Deferred compensation plan assets 70 — — 70 Total assets 70 759 — 829 Liabilities: Commodity derivatives — 2 — 2 Interest rate derivatives — 3 — 3 Total liabilities — 5 — 5 Total recurring fair value measurements $ 70 $ 754 $ — $ 824
Fair Value Measurements, Nonrecurring [Table Text Block]	The following table presents the fair value and fair value adjustments (in millions) for the Company's 2015 and 2013 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks: Fair Fair Value Management's Price Outlooks Value Adjustment Oil Gas South Texas - Eagle Ford Shale December 2015 $ 483 $ (846 ) $ 52.82 $ 3.34 South Texas - Other September 2015 $ 88 $ (72 ) $ 57.41 $ 3.46 West Panhandle March 2015 $ 61 $ (138 ) $ 65.02 $ 3.83 Raton December 2013 $ 534 $ (1,495 ) $ 80.40 $ 4.43
Fair Value of Assets Classified as Held for Sale [Table Text Block]	The following table presents the fair value adjustments made by the Company during the years ended December 31, 2014 and 2013 related to assets associated with divestitures: Year Ended December 31, 2014 Year Ended December 31, 2013 Classification Estimated Fair Value Less Costs to Sell Fair Value Adjustment Estimated Fair Value Less Costs to Sell Fair Value Adjustment (in millions) Hugoton field Discontinued operations $ 328 $ (34 ) Barnett Shale field Discontinued operations $ 149 $ (174 ) $ 180 $ (190 ) Pioneer Alaska Discontinued operations $ 253 $ (97 ) $ 351 $ (539 ) Sendero Continuing operations $ 31 $ (25 )
Fair Value Measurements Not Carried At Fair Value	Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (in millions) Current portion of long-term debt $ 448 $ 462 $ — $ — Long-term debt $ 3,207 $ 3,206 $ 2,648 $ 2,938

Derivative Financial Instrume30

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Oil Derivative Contracts Volume And Weighted Average Price	The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of December 31, 2015 and the weighted average oil prices for those contracts: 2016 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Swap contracts: Volume (Bbl) (a) 35,000 35,000 — — — Price per Bbl $ 59.88 $ 59.88 $ — $ — $ — Collar contracts with short puts: Volume (Bbl) (a) 63,000 68,000 112,000 112,000 34,000 Price per Bbl: Ceiling $ 73.29 $ 72.43 $ 75.94 $ 75.94 $ 70.42 Floor $ 63.04 $ 62.08 $ 65.41 $ 65.41 $ 57.65 Short put $ 43.17 $ 42.94 $ 47.03 $ 47.03 $ 47.65 _______________ (a) During the period from January 1, 2016 through February 16, 2016, the Company converted 25,000 Bbls per day of March through June 2016 collar contracts with short puts with a ceiling price of $71.02 per Bbl, a floor price of $60.00 per Bbl and a short put price of $48.00 per Bbl into new swap contracts covering the same period with a fixed price of $43.54 per Bbl.
Schedule of NGL Derivative Volumes and Weighted Average Prices [Table Text Block]	2016 First Quarter Second Quarter Third Quarter Fourth Quarter Propane swap contracts (a): Volume (Bbl) 7,500 7,500 7,500 7,500 Price per Bbl $ 21.57 $ 21.57 $ 21.57 $ 21.57
Gas Volume And Weighted Average Price	The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of December 31, 2015 and the weighted average gas prices for those contracts: 2016 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Swap contracts: Volume (MMBtu) 70,000 70,000 70,000 70,000 — Price per MMBtu $ 4.06 $ 4.06 $ 4.06 $ 4.06 $ — Collar contracts with short puts: Volume (MMBtu) 180,000 180,000 180,000 180,000 — Price per MMBtu: Ceiling $ 4.01 $ 4.01 $ 4.01 $ 4.01 $ — Floor $ 3.24 $ 3.24 $ 3.24 $ 3.24 $ — Short put $ 2.78 $ 2.78 $ 2.78 $ 2.78 $ — Basis swap contracts: Gulf Coast basis swap contracts (a) 10,000 10,000 10,000 10,000 — Price differential ($/MMBtu) $ — $ — $ — $ — $ — Mid-Continent index swap volume (a) 15,000 15,000 15,000 15,000 45,000 Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) Permian Basin index swap volume (b) (c) 6,813 — — — — Price differential ($/MMBtu) $ 0.26 $ — $ — $ — $ — ____________________ (a) Represents swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts. (b) Represents swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California. (c) During the period from January 1, 2016 through February 16, 2016, the Company entered into (i) an additional 40,000 MMBtu per day of basis swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California for the November 2016 through March 2017 time period with a fixed price of $0.37 per MMBtu and (ii) an additional 25,000 MMBtu per day of basis swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California for December 2016 with a fixed price of $0.53 per MMBtu.
Offsetting Asset and Liability [Table Text Block]	The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following: Fair Value of Derivative Instruments as of December 31, 2015 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 695 $ (1 ) $ 694 Commodity price derivatives Derivatives - noncurrent $ 64 $ — 64 $ 758 Liability Derivatives: Commodity price derivatives Derivatives - current $ 1 $ (1 ) $ — Commodity price derivatives Derivatives - noncurrent $ 1 $ — 1 $ 1 Fair Value of Derivative Instruments as of December 31, 2014 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 579 $ (1 ) $ 578 Commodity price derivatives Derivatives - noncurrent $ 182 $ (1 ) 181 $ 759 Liability Derivatives: Commodity price derivatives Derivatives - current $ 1 $ (1 ) $ — Interest rate derivatives Derivatives - current $ 3 $ — 3 Commodity price derivatives Derivatives - noncurrent $ 3 $ (1 ) 2 $ 5
Schedule of Derivative Gains and Losses Recognized on Statement of Operations [Table Text Block]	The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recognized in Earnings on Derivatives Amount of Gain/(Loss) Recognized in Earnings on Derivatives Year Ended December 31, 2015 2014 2013 (in millions) Commodity price derivatives Derivative gains, net $ 873 $ 697 $ (6 ) Interest rate derivatives Derivative gains, net 6 15 10 Total $ 879 $ 712 $ 4
Schedule of Derivative Assets and Liabilities by Counterparty [Table Text Block]	The following table provides the Company's net derivative assets by counterparty as of December 31, 2015 : Net Assets (in millions) Merrill Lynch $ 138 Citibank, N.A. 109 BMO Financial Group 108 Societe Generale 105 J. Aron & Company 81 Morgan Stanley 53 Wells Fargo Bank, N.A. 51 JP Morgan Chase 49 Macquarie Bank 34 Den Norske Bank 16 Nextera Energy 9 Toronto Dominion 4 Total $ 757

Exploratory Well Costs (Tables)

Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well And Project Activity	The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Beginning capitalized exploratory well costs $ 305 $ 159 $ 213 Additions to exploratory well costs pending the determination of proved reserves 1,178 1,860 1,220 Reclassification due to determination of proved reserves (1,160 ) (1,628 ) (1,045 ) Divestitures — (47 ) (93 ) Impairment of properties — (13 ) (87 ) Exploratory well costs charged to exploration and abandonment expense (a) (17 ) (26 ) (49 ) Ending capitalized exploratory well costs $ 306 $ 305 $ 159 _______________ (a) Includes exploration and abandonment expense of $43 million in 2013 that is included in discontinued operations in the accompanying consolidated statements of operations.
Capitalized Exploratory Costs And The Number Of Projects For Which Exploratory Costs Have Been Capitalized	The following table provides an aging, as of December 31, 2015 , 2014 and 2013 of capitalized exploratory 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: As of December 31, 2015 2014 2013 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 303 $ 305 $ 116 More than one year 3 — 43 $ 306 $ 305 $ 159 Number of projects with exploratory well costs that have been suspended for a period greater than one year 1 — 1

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Components Of Long-Term Debt	Long-term debt, including the effects of issuance costs, issuance discounts and net deferred fair value hedge losses, consisted of the following components at December 31, 2015 and 2014 : December 31, 2015 2014 (in millions) Outstanding debt principal balances: 5.875% senior notes due 2016 (a) $ 455 $ 455 6.65% senior notes due 2017 485 485 6.875% senior notes due 2018 450 450 7.500% senior notes due 2020 450 450 3.45% senior notes due 2021 500 — 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 — 7.20% senior notes due 2028 250 250 3,690 2,690 Issuance costs and discounts (35 ) (41 ) Net deferred fair value hedge losses — (1 ) Long-term debt 3,655 2,648 Less current portion of long-term debt (a) 448 — Long-term debt $ 3,207 $ 2,648 ______________________________ (a) These notes, net of $7 million of unamortized issuance costs, issuance discounts and deferred fair value hedge losses, are classified as current in the accompanying consolidated balance sheets.
Principal Maturities Of Long-Term Debt	Principal maturities of long-term debt at December 31, 2015 , are as follows (in millions): 2016 $ 455 2017 $ 485 2018 $ 450 2019 $ — 2020 $ 450 Thereafter $ 1,850
Interest Expense	The following amounts have been incurred and charged to interest expense for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Cash payments for interest $ 148 $ 193 $ 183 Amortization of issuance discounts 13 12 12 Amortization of capitalized loan fees 5 5 5 Net changes in accruals 25 (22 ) (6 ) Interest incurred 191 188 194 Less capitalized interest (4 ) (4 ) (10 ) Total interest expense $ 187 $ 184 $ 184

Incentive Plans (Tables)

Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Number Of Shares Available Under The Company's Long Term Incentive Plan	The following table shows the number of shares available for issuance pursuant to awards under the LTIP at December 31, 2015 : Approved and authorized awards 9,100,000 Awards issued after May 3, 2006 (7,017,999 ) Awards available for future grant 2,082,001
Schedule Of Employee Stock Purchase Plan	The following table shows the number of shares available for issuance under the ESPP at December 31, 2015 : Approved and authorized shares 1,250,000 Shares issued (833,078 ) Shares available for future issuance 416,922
Schedule Of Compensation Expense For Each Type Of Incentive Award	The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award and the associated income tax benefit for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Restricted stock-Equity Awards $ 70 $ 65 $ 57 Restricted stock-Liability Awards 22 28 40 Stock options (a) — 2 3 Performance unit awards 18 13 9 ESPP 2 2 2 Other — — 1 Total $ 112 $ 110 $ 112 Income tax benefit $ 34 $ 33 $ 36 _____________________ (a) Cash proceeds received from stock option exercises during 2014 and 2013 amounted to $6 million and $5 million , respectively. There were no stock option exercises during 2015 .
Schedule Of Restricted Stock Award Activity	The following table reflects the restricted stock award activity for the year ended December 31, 2015 : Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 1,233,539 $ 140.57 328,087 Shares granted 441,477 $ 153.55 161,692 Shares forfeited (46,429 ) $ 155.52 (33,082 ) Shares vested (546,937 ) $ 138.76 (185,666 ) Outstanding at end of year 1,081,650 $ 151.50 271,031
Schedule Of Weighted-Average Assumptions To Estimate The Fair Value
Schedule Of Stock Options Awards Activity	A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2015 is presented below: Number of Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Life Aggregate Intrinsic Value (in years) (in millions) Outstanding at beginning of year 199,058 $ 77.51 Options exercised — $ — Outstanding at end of year 199,058 $ 77.51 4.96 $ 10 Exercisable at end of year 199,058 $ 77.51 4.96 $ 10
Schedule of Assumptions Used [Table Text Block]	The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2015 , 2014 and 2013 : 2015 2014 2013 Risk-free interest rate 1.03% 0.62% 0.40% Range of volatilities 26.1 % - 41.3% 29.0 % - 41.5% 30.4 % - 42.9%
Schedule Of Performance Unit Activity	The following table summarizes the performance unit activity for the year ended December 31, 2015 : Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 154,733 $ 207.88 Units granted 82,431 $ 222.33 Units forfeited — $ — Units vested (b) (88,617 ) $ 189.71 Ending performance unit awards 148,547 $ 226.74 _____________________ (a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. (b) Of the 88,617 units that vested during 2015, 87,551 units vested according to the scheduled timing of the associated award and 1,066 units, which were originally scheduled to vest in 2016 and 2017, vested upon retirement of the officer to whom the performance unit awards were granted. On December 31, 2015 , the service period lapsed on 88,374 performance unit awards that earned 1.5 shares for each vested award, representing 132,566 aggregate shares of common stock issued on January 4, 2016. The vested performance units that earned 1.5 shares for each vested award included 87,551 units vested in the current year and 823 units that vested in 2014 upon the retirement of the officer to whom the performance unit awards were granted.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Schedule Of Asset Retirement Obligations	The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Beginning asset retirement obligations $ 189 $ 194 $ 198 Obligations assumed in acquisitions — 6 — New wells placed on production 4 5 6 Changes in estimates (a) 103 7 8 Disposition of wells — (14 ) (16 ) Obligations settled (23 ) (21 ) (15 ) Accretion of discount on continuing operations 12 12 12 Accretion of discount on discontinued operations — — 1 Ending asset retirement obligations $ 285 $ 189 $ 194 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The increase in 2015 is primarily due to the forecasted timing of abandoning the Company's oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company's producing wells.

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Drilling Commitments [Table Text Block]	future minimum drilling commitments at December 31, 2015 include only drilling rig obligations that are expected to be paid as follows (in millions): 2016 $ 179 2017 $ 110 2018 $ 64 2019 $ 10 2020 $ — Thereafter $ —
Future Minimum Lease Commitments	Future minimum lease commitments under noncancelable operating leases at December 31, 2015 are as follows (in millions): 2016 $ 24 2017 $ 23 2018 $ 21 2019 $ 21 2020 $ 17 Thereafter $ 15
Future Minimum Gathering, Processing And Transportation Fees	Future minimum purchase, gathering, processing, transportation and fractionation commitments at December 31, 2015 are as follows (in millions): 2016 $ 451 2017 $ 479 2018 $ 476 2019 $ 467 2020 $ 465 Thereafter $ 1,145

Major Customers (Tables)

Major Customers (Tables)	12 Months Ended
	Dec. 31, 2015
Major Customers And Derivative Counterparties [Abstract]
Schedule of Revenue by Major Customer	The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas production revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2015 : Year Ended December 31, 2015 2014 2013 Plains Marketing LP 22 % 29 % 28 % Occidental Energy Marketing Inc. 18 % 16 % 13 % Vitol, Inc. 18 % 9 % 5 % Enterprise Products Partners L.P. 12 % 13 % 13 %
Schedule of Sales of Purchased Oil and Gas by Major Customer	Year Ended December 31, 2015 2014 2013 Valero Marketing and Supply Company 37 % 61 % 51 % Occidental Energy Marketing Inc. 18 % — % 1 % Plains Marketing LP 18 % — % — % EDF Trading North America LLC 4 % 9 % 20 %

Interest And Other Income (Tabl

Interest And Other Income (Tables)	12 Months Ended
	Dec. 31, 2015
Interest and Other Income [Abstract]
Interest And Other Income	The following table provides the components of the Company's interest and other income during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Equity interest in income of EFS Midstream (a) $ 5 $ 13 $ 7 Deferred compensation plan income 4 3 6 Interest income 3 — — Other income 10 10 10 Total interest and other income $ 22 $ 26 $ 23 ______________________ (a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. See Note C for additional information on the Company's sale of EFS Midstream.

Other Expense (Tables)

Other Expense (Tables)	12 Months Ended
	Dec. 31, 2015
Other Expense, Nonoperating [Abstract]
Schedule Of Components Of Other Expense	The following table provides the components of the Company's other expense during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Idle drilling and well service equipment charges (a) $ 92 $ 7 $ 10 Impairment of inventory and other property and equipment (b) 86 8 62 Transportation commitment charges (c) 53 46 39 Loss from vertical integration services (d) 34 16 5 Restructuring charges (e) 23 — — Contingency and environmental accrual adjustments — — 9 Other 27 29 18 Total other expense $ 315 $ 106 $ 143 ____________________ (a) Primarily represents expenses attributable to idle drilling rig fees which are not chargeable to joint operations. (b) Primarily represents charges of $71 million , $8 million and $36 million to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2015 , 2014 and 2013, respectively, and a charge of $25 million for the year ended December 31, 2013 to reduce the carrying value of Sendero to its estimated fair value. See Notes C and D for additional information on the fair value of material and supplies inventory and Sendero, respectively. (c) Primarily represents firm transportation payments on excess pipeline capacity commitments. (d) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2015 , 2014 and 2013 , these net losses include $298 million , $374 million and $285 million of gross vertical integration revenues, respectively, and $332 million , $390 million and $290 million of total vertical integration costs and expenses and elimination of revenues associated with intercompany transactions, respectively. (e) Represents restructuring costs associated with the Company's restructuring of its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. See Note B for additional information on the restructuring charges.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Summary Of Open Tax Years, By Jurisdiction	The Company's earliest open years in its key jurisdictions are as follows: U.S. federal 2014 Various U.S. states 2010 South Africa 2010
Schedule Of Income Tax (Provision) Benefit Allocation	The Company's income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Income tax (provision) benefit from continuing operations $ 155 $ (556 ) $ 213 Income tax benefit from discontinued operations $ 2 $ 60 $ 249 Changes in equity: Excess tax benefit related to stock-based compensation $ 7 $ 19 $ 18 Tax benefit attributable to conversion of 2.875% senior convertible notes $ — $ — $ 38 Tax benefit attributable to 2013 merger with Pioneer Southwest $ — $ — $ 200
Income Tax (Provision) Benefit Attributable To Income From Continuing Operations	The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Current: U.S. federal $ (22 ) $ (3 ) $ (11 ) U.S. state (1 ) (1 ) — (23 ) (4 ) (11 ) Deferred: U.S. federal 165 (537 ) 208 U.S. state 13 (15 ) 16 178 (552 ) 224 Income tax (provision) benefit from continuing operations $ 155 $ (556 ) $ 213
Schedule Of Effective Income Tax Rate Reconciliation	Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income (loss) from continuing operations are as follows for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions, except percentages) Income (loss) from continuing operations before income taxes $ (421 ) $ 1,597 $ (574 ) Less: Net income attributable to noncontrolling interests — — (39 ) Income (loss) from continuing operations attributable to common stockholders before income taxes (421 ) 1,597 (613 ) Federal statutory income tax rate 35 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate 147 (559 ) 215 State income tax (provision) benefit (net of federal tax) 8 (10 ) 10 Premier Silica benefit — 21 — Other — (8 ) (12 ) Income tax (provision) benefit from continuing operations $ 155 $ (556 ) $ 213 Effective income tax rate, excluding net income attributable to the noncontrolling interests 37 % 35 % 35 %
Schedule Of Deferred Tax Assets And Deferred Tax Liabilities	The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2015 and 2014 : December 31, 2015 2014 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 441 $ 330 Asset retirement obligations 102 68 Incentive plans 75 71 Other 102 74 Total deferred tax assets 720 543 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (1,997 ) (1,881 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (227 ) (251 ) Net deferred hedge gains (272 ) (280 ) Other — (95 ) Total deferred tax liabilities (2,496 ) (2,507 ) Net deferred tax liability $ (1,776 ) $ (1,964 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2015 consist of $1.2 billion of U.S. federal NOLs which expire primarily between 2032 and 2035 and $132 million of Colorado NOLs which expire between 2028 and 2034.

Net Income (Loss) Per Share A40

Net Income (Loss) Per Share Attributable To Common Stockholders (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted	The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Income (loss) from continuing operations $ (266 ) $ 1,041 $ (400 ) Participating basic earnings (a) — (10 ) — Basic and diluted net income (loss) from continuing operations (266 ) 1,031 (400 ) Basic and diluted net loss from discontinued operations (7 ) (111 ) (438 ) Basic and diluted net income (loss) attributable to common stockholders $ (273 ) $ 920 $ (838 ) ______________________ (a) Unvested restricted stock awards and Pioneer Southwest phantom unit awards (prior to the December 2013 Pioneer Southwest merger) represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

Summary Of Significant Accoun41

Summary Of Significant Accounting Policies (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Rate	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Dec. 17, 2013Rateshares	Jun. 30, 2010Rate
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable - trade	$ 384	$ 436
Allowances for doubtful accounts	$ 1	1
Natural gas processing plants number	7
Treating facilities number	8
Company operated natural gas processing plants	1
Company Operated Treating Facilities	8
Third party operated natural gas processing plants	6
Nonoperated treating facilities	6
Third party revenues, processing plants and treating facilities	$ 39	56	$ 53
Third party expenses, processing plants and treating facilities	$ 27	$ 24	$ 21
Equity Method Investment, Ownership Percentage | Rate	50.10%
Stock Issued During Period, Shares, New Issues | shares		5,750,000	10,350,000
Proceeds from Issuance of Common Stock	$ 0	$ 980	$ 1,281
Noncontrolling interest in consolidating subsidiaries	7	8
Net income attributable to noncontrolling interests	0	0	(39)
Pioneer Southwest merger transaction costs		(1)	(4)
Net transfers from noncontrolling interest			365
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests			0
Deferred tax benefit associated with the Pioneer Southwest merger	0	0	200
Restructuring and Related Cost, Incurred Cost	23	0	0
Restructuring Reserve	4
Deferred Tax Liabilities, Net, Noncurrent	1,776	1,964
Pioneer Southwest [Member]
Summary Of Significant Accounting Policies [Line Items]
Share Per Unit Exchange Ratio | shares				0.2325
EFS Midstream [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of interest sold | Rate					49.90%
Limited Partner Interest [Member]
Summary Of Significant Accounting Policies [Line Items]
Partnerships interest | Rate				52.40%
General Partner Interest [Member]
Summary Of Significant Accounting Policies [Line Items]
Partnerships interest | Rate				0.10%
Additional Paid-In Capital [Member]
Summary Of Significant Accounting Policies [Line Items]
Pioneer Southwest merger transaction costs		(1)	(4)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests			169
Deferred tax benefit associated with the Pioneer Southwest merger			200
Additional Paid-In Capital [Member] | Pioneer Southwest [Member]
Summary Of Significant Accounting Policies [Line Items]
Pioneer Southwest merger transaction costs		$ (1)	(4)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests			169
Deferred tax benefit associated with the Pioneer Southwest merger			$ 200
Employee Severance [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost	17
Contract Termination [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost	6
Cash [Member] | Employee Severance [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost	16
Deferred Compensation, Share-based Payments [Member] | Employee Severance [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost	1
Leasehold Improvements [Member] | Contract Termination [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost	2
Property Subject to Operating Lease [Member] | Contract Termination [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost	4
Adjustments for New Accounting Principle, Early Adoption [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred Tax Liabilities, Net, Noncurrent	161
Unamortized Debt Issuance Expense	$ 17

Summary Of Significant Accoun42

Summary Of Significant Accounting Policies (Schedule of Inventory) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Schedule of Inventory [Line Items]
Materials and supplies inventories	[1]	$ 132	$ 223
Commodities		23	18
Inventories		155	241
Net materials and supplies inventories reserves		$ 78	$ 22
[1]	As of December 31, 2015 and 2014, the Company's materials and supplies inventories were net of valuation allowances of $78 million and $22 million, respectively. See Note D for additional information regarding inventory impairments.

Summary of Significant Accoun43

Summary of Significant Accounting Policies (Schedule of Other Property Plant and Equipment) (Details) $ in Millions		Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net	[1]	$ 1,523	$ 1,391
Accumulated depreciation property, plant and equipment, other assets		$ 711	563
Fracture Stimulation Fleets		8
Proved and Unproved Sand Leaseholds [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net	[2]	$ 473	469
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		468	440
Wells and Related Equipment and Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		287	338
Water infrastructure [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		180	10
Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		21	35
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		67	70
Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		$ 27	$ 29
[1]	At December 31, 2015 and 2014, other property and equipment was net of accumulated depreciation of $711 million and $563 million, respectively.
[2]	Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Discontinued Operations Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Rate	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)Rateshares	Dec. 17, 2013shares
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Issuance of treasury stock to acquire outstanding PSE units, shares | shares			3,956,000
Gain on disposition of assets, net	$ 782	$ 9	$ 209
Equity Method Investment, Ownership Percentage | Rate	50.10%
Equity Method Investment, Net Sales Proceeds	$ 1,000
Equity Method Investment, Realized Gain (Loss) on Disposal	777
Idle Rig Expense	92	7	10
Proceeds from disposition of assets, net of cash sold	553	877	711
Sendero [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net		1
Proceeds from Divestiture of Interest in Consolidated Subsidiaries		31
Idle Rig Expense	40	7
Gaines Dawson [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net		2
Proceeds from disposition of assets, net of cash sold		72
Wolfcamp [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net			181
Proceeds from disposition of assets, net of cash sold			$ 624
Joint Venture Investment Ownership Percentage | Rate			40.00%
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds			$ 1,800
Maximum Payments From Related Party For Exploration Drilling And Completion Costs	197		$ 1,200
Payments From Related Party For Exploration Drilling And Completion Costs Percent | Rate			75.00%
West Panhandle [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net			$ 22
Proceeds from disposition of assets, net of cash sold			38
Other Assets [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net	5	$ 6	6
Lease Contract for Next 12 Months [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Drilling rigs leased		12
Lease Contract for Year 2 [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Drilling rigs leased		8
Discontinued Operations [Member] | Hugoton field [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Proceeds from disposition of assets, net of cash sold		$ 328
Discontinued Operations [Member] | Pioneer Alaska [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Proceeds from disposition of assets, net of cash sold		267
Discontinued Operations [Member] | Barnett Shale Field [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net			9
Proceeds from disposition of assets, net of cash sold		$ 150	$ 34
Limited Partner Interest [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Partners' Capital Account, Acquisitions		5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		$ 54
Pioneer Southwest [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Share Per Unit Exchange Ratio | shares				0.2325
Proceeds To Be Received In Future Year [Member] [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Equity Method Investment, Net Sales Proceeds	500
Proceeds Received Current Year [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Equity Method Investment, Net Sales Proceeds	$ 530

Acquisitions and Divestitures45

Acquisitions and Divestitures (Components of Discontinued Operations) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and Gas Revenue		$ 2,178	$ 3,599	$ 3,088
Interest and other		22	26	23
Gain on disposition of assets, net		782	9	209
Oil and Gas Production Expense		717	693	588
Production and Ad Valorem Taxes From Discontinued Operations		145	220	192
Depletion, depreciation and amortization		1,385	1,047	889
Impairment of oil and gas properties		1,056	0	1,495
Exploration Abandonment and Impairment Expense		99	177	97
General and administrative		327	333	296
Accretion of discount on asset retirement obligations		12	12	12
Interest		187	184	184
Other		315	106	143
Costs and expenses, Total		5,246	3,475	4,232
Current		(23)	(4)	(11)
Deferred		178	(552)	224
Loss from discontinued operations		(7)	(111)	(438)
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and Gas Revenue			198	329
Total revenues and other income from discontinued operations		1	238	376
Oil and Gas Production Expense			60	117
Impairment of oil and gas properties	[1]		305	729
Costs and expenses, Total		10	409	1,063
Income (loss) from discontinued operations before income taxes		(9)	(171)	(687)
Current		(1)	0	(6)
Deferred		3	60	255
Loss from discontinued operations		$ (7)	$ (111)	(438)
Discontinued Operations [Member] | Barnett Shale Field [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposition of assets, net				$ 9
[1]	(b)Costs and expenses during 2015 were primarily related to an arbitration award associated with plugging and abandonment obligations for two Gulf of Mexico wells from which Pioneer withdrew in 2009. The Company incurred noncash impairment charges of $305 million and $729 million during the years ended December 31, 2014 and 2013, respectively, on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 and 2013 also included oil and gas production costs of $60 million and $117 million, respectively. See Note D for additional information regarding the noncash impairment charges related to the Hugoton assets, the Barnett Shale assets and Pioneer Alaska.

Disclosures About Fair Value 46

Disclosures About Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Inventory Write-down	$ 71	$ 8	$ 23
discount rate used in impairment calculation	10.00%
Colorado [Member]
Impairment of Long-Lived Assets Held-for-use	$ 7	$ 50

Disclosures About Fair Value 47

Disclosures About Fair Value Measurements (Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	$ 73	$ 70
Assets, Fair Value Disclosure	831	829
Liabilities, Fair Value Disclosure	1	5
Recurring Measurements, (Fair Value, Total)	830	824
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	758	759
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	2
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure		3
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	73	70
Assets, Fair Value Disclosure	73	70
Liabilities, Fair Value Disclosure	0	0
Recurring Measurements, (Fair Value, Total)	73	70
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure		0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	0	0
Assets, Fair Value Disclosure	758	759
Liabilities, Fair Value Disclosure	1	5
Recurring Measurements, (Fair Value, Total)	757	754
Significant Other Observable Inputs (Level 2) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	758	759
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	2
Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure		3
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	0	0
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	0
Recurring Measurements, (Fair Value, Total)	0	0
Significant Unobservable Inputs (Level 3) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 0	0
Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure		$ 0

Disclosures About Fair Value 48

Disclosures About Fair Value Measurements (Measured On A Nonrecurring Basis) (Details) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2015USD ($)$ / Mcf$ / bbl	Sep. 30, 2015USD ($)$ / Mcf$ / bbl	Dec. 31, 2015USD ($)$ / Mcf$ / bbl	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)$ / Mcf$ / bbl
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties			$ (1,056)	$ 0	$ (1,495)
Management oil price outlook | $ / bbl	65.02	57.41	52.82		80.40
Management gas price outlook | $ / Mcf	3.83	3.46	3.34		4.43
South Texas Eagle Ford Shale [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group			$ 483
Impairment of oil and gas properties			$ (846)
South Texas Edwards And Austin Chalk [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group		$ 88
Impairment of oil and gas properties		$ (72)
West Panhandle [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group	$ 61
Impairment of oil and gas properties	$ (138)
Raton Field [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group					$ 534
Impairment of oil and gas properties					$ (1,495.2)

Disclosures About Fair Value 49

Disclosures About Fair Value Measurements Disclosures About Fair Value Measurements (Fair Value of Assets Classified as Held For Sale) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Tangible Asset Impairment Charges	[1]	$ (86)	$ (8)	$ (62)
Impairment of oil and gas properties		$ (1,056)	0	(1,495)
Hugoton field [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group			328
Barnett Shale Field [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group			149	180
Pioneer Alaska [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group			253	351
Sendero [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group				31
Tangible Asset Impairment Charges				(25)
Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties	[2]		(305)	(729)
Discontinued Operations [Member] | Hugoton field [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties			(34)
Discontinued Operations [Member] | Barnett Shale Field [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties			(174)	(190)
Discontinued Operations [Member] | Pioneer Alaska [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties			$ (97)	$ (539)
[1]	(c)Primarily represents firm transportation payments on excess pipeline capacity commitments.
[2]	(b)Costs and expenses during 2015 were primarily related to an arbitration award associated with plugging and abandonment obligations for two Gulf of Mexico wells from which Pioneer withdrew in 2009. The Company incurred noncash impairment charges of $305 million and $729 million during the years ended December 31, 2014 and 2013, respectively, on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 and 2013 also included oil and gas production costs of $60 million and $117 million, respectively. See Note D for additional information regarding the noncash impairment charges related to the Hugoton assets, the Barnett Shale assets and Pioneer Alaska.

Disclosures About Fair Value 50

Disclosures About Fair Value Measurements (Financial Assets and Liabilities Not Carried At Fair Value) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Long-term Debt, Current Maturities	$ 448	$ 0
Long-term Debt	3,655	2,648
Reported Value Measurement [Member]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Long-term Debt, Current Maturities	448	0
Long-term Debt	3,207	2,648
Estimate of Fair Value Measurement [Member]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Long-term Debt, Current Maturities	462	0
Long-term Debt	$ 3,206	$ 2,938

Derivative Financial Instrume51

Derivative Financial Instruments (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 16, 2016
Schedule of Trading Securities and Other Trading Assets [Line Items]
Proceeds from Termination of Interest Rate Derivatives	$ 3
Subsequent Event [Member]
Schedule of Trading Securities and Other Trading Assets [Line Items]
Derivative fixed interest rate		1.98%
Notional amount of debt		$ 200

Derivative Financial Instrume52

Derivative Financial Instruments (Oil Derivative Contracts Volume And Weighted Average Price) (Details)		Feb. 16, 2016bbl / d$ / bbl	Dec. 31, 2015bbl / d$ / bbl
Oil contracts, price per bbl [Member] | Swap Contracts For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price			59.88
Oil contracts, price per bbl [Member] | Swap Contracts For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price			59.88
Oil contracts, price per bbl [Member] | Swap Contracts For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Oil contracts, price per bbl [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Oil contracts, price per bbl [Member] | Swap Contracts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price			73.29
Derivative, Average Floor Price			63.04
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Notional Amount, Price Per Unit			43.17
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price			72.43
Derivative, Average Floor Price			62.08
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Notional Amount, Price Per Unit			42.94
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price			75.94
Derivative, Average Floor Price			65.41
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Notional Amount, Price Per Unit			47.03
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price			75.94
Derivative, Average Floor Price			65.41
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Notional Amount, Price Per Unit			47.03
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price			70.42
Derivative, Average Floor Price			57.65
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for Year 2 [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Notional Amount, Price Per Unit			47.65
Oil contracts [Member] | Swap Contracts For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			35,000
Oil contracts [Member] | Swap Contracts For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			35,000
Oil contracts [Member] | Swap Contracts For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			0
Oil contracts [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			0
Oil contracts [Member] | Swap Contracts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			0
Oil contracts [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1],[2]		63,000
Oil contracts [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1],[2]		68,000
Oil contracts [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1],[2]		112,000
Oil contracts [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1],[2]		112,000
Oil contracts [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1],[2]		34,000
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For March to June of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price		71.02
Derivative, Average Floor Price		60
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For March to June of Year One [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Notional Amount, Price Per Unit		48
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Swap Contracts For March to June of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price		43.54
Subsequent Event [Member] | Oil contracts [Member] | Collar Contracts With Short Puts For March to June of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1],[2]	25,000
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmMmVmODZiZmUyZjQ4OWM5NDM5OGU1N2U3ZmEzMmNhfFRleHRTZWxlY3Rpb246NUQxNTgxNzUwMjIwNkY4QTlFOUNCREM4MTA5Q0E2Q0EM}
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmMmVmODZiZmUyZjQ4OWM5NDM5OGU1N2U3ZmEzMmNhfFRleHRTZWxlY3Rpb246NzY1OTVCOUEyNTBBQTgzNDhBRjFCREM4MTA5QzY4MUUM}

Derivative Financial Instrume53

Derivative Financial Instruments Derivative Financial Instruments (NGL Derivative Contracts Volume and Weighted Average Price) (Details) - Propane [Member]	Dec. 31, 2015bbl / d$ / bbl
NGL contract, in BBLS [Member] | Swap Contracts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	7,500
NGL contract, in BBLS [Member] | Swap Contracts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	7,500
NGL contract, in BBLS [Member] | Swap Contracts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	7,500
NGL contract, in BBLS [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	7,500
NGL contracts, price per BBL [Member] | Swap Contracts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	21.57
NGL contracts, price per BBL [Member] | Swap Contracts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	21.57
NGL contracts, price per BBL [Member] | Swap Contracts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	21.57
NGL contracts, price per BBL [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	21.57

Derivative Financial Instrume54

Derivative Financial Instruments (Gas Derivative Contracts Volume And Weighted Average Price) (Details)		Feb. 16, 2016MMBTU / d$ / MMBTU	Dec. 31, 2015MMBTU / d$ / MMBTU
Gas contracts, in MMBTU [Member] | Swap Contracts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			70,000
Gas contracts, in MMBTU [Member] | Swap Contracts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			70,000
Gas contracts, in MMBTU [Member] | Swap Contracts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			70,000
Gas contracts, in MMBTU [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			70,000
Gas contracts, in MMBTU [Member] | Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Gas contracts, in MMBTU [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			180,000
Gas contracts, in MMBTU [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			180,000
Gas contracts, in MMBTU [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			180,000
Gas contracts, in MMBTU [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			180,000
Gas contracts, in MMBTU [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Gas contracts, price per MMBTU [Member] | Swap Contracts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			4.06
Gas contracts, price per MMBTU [Member] | Swap Contracts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			4.06
Gas contracts, price per MMBTU [Member] | Swap Contracts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			4.06
Gas contracts, price per MMBTU [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			4.06
Gas contracts, price per MMBTU [Member] | Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price			4.01
Derivative, Average Floor Price			3.24
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Notional Amount, Price Per Unit			2.78
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price			4.01
Derivative, Average Floor Price			3.24
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Notional Amount, Price Per Unit			2.78
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price			4.01
Derivative, Average Floor Price			3.24
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Notional Amount, Price Per Unit			2.78
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price			4.01
Derivative, Average Floor Price			3.24
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Notional Amount, Price Per Unit			2.78
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price			0
Derivative, Average Floor Price			0
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts for Year 2 [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Notional Amount, Price Per Unit			0
Gulf Coast [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		10,000
Gulf Coast [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		10,000
Gulf Coast [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		10,000
Gulf Coast [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		10,000
Gulf Coast [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Gulf Coast [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Gulf Coast [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Gulf Coast [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Gulf Coast [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Gulf Coast [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Mid-Continent [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		15,000
Mid-Continent [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		15,000
Mid-Continent [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		15,000
Mid-Continent [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		15,000
Mid-Continent [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		45,000
Mid-Continent [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Permian Basin [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		6,813
Permian Basin [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Permian Basin [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Permian Basin [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Permian Basin [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Permian Basin [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.26
Permian Basin [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Permian Basin [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Permian Basin [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Permian Basin [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Subsequent Event [Member] | Permian Basin [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for November 2016 to March 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]	40,000
Subsequent Event [Member] | Permian Basin [Member] | Gas contracts, in MMBTU [Member] | Basis Swap Contracts for December of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]	25,000
Subsequent Event [Member] | Permian Basin [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for November 2016 to March 2017 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price		0.37
Subsequent Event [Member] | Permian Basin [Member] | Gas contracts, price per MMBTU [Member] | Basis Swap Contracts for December of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price		0.53
[1]	Represents swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts.

Derivative Financial Instrume55

Derivative Financial Instruments (Offsetting Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Asset, Current	$ 694	$ 578
Derivative Asset, Noncurrent	64	181
Derivative Liability, Current	0	3
Derivative Liability, Noncurrent	1	2
Not Designated As Hedging Instruments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	758	759
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	5
Derivative Current [Member] | Not Designated As Hedging Instruments [Member] | Commodity Price Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset	695	579
Total derivatives, Liability	1	1
Derivative Assets Offset In Balance Sheet	(1)	(1)
Derivative Liabilities Offset In Balance Sheet	1	1
Derivative Asset, Current	694	578
Derivative Liability, Current	0	0
Derivative Current [Member] | Not Designated As Hedging Instruments [Member] | Interest Rate Derivatives [Member]
Derivative [Line Items]
Total derivatives, Liability		3
Derivative Liabilities Offset In Balance Sheet		0
Derivative Liability, Current		3
Derivative Noncurrent [Member] | Not Designated As Hedging Instruments [Member] | Commodity Price Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset	64	182
Total derivatives, Liability	1	3
Derivative Assets Offset In Balance Sheet	0	(1)
Derivative Liabilities Offset In Balance Sheet	0	1
Derivative Asset, Noncurrent	64	181
Derivative Liability, Noncurrent	$ 1	$ 2

Derivative Financial Instrume56

Derivative Financial Instruments (Derivative Obligations Under Terminated Hedge Arrangements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative gains, net	$ 879	$ 712	$ 4
Interest Rate Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	6	15	10
Commodity Price Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	$ 873	$ 697	$ (6)

Schedule of Derivative Assets a

Schedule of Derivative Assets and Liabilities by Counterparty (Details) $ in Millions	Dec. 31, 2015USD ($)
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 757
Merrill Lynch [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	138
Citibank, N.A. [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	109
BMO Financial Group [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	108
Societe Generale [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	105
J. Aron & Company [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	81
Morgan Stanley [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	53
Wells Fargo Bank, N.A. [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	51
JP Morgan Chase [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	49
Macquarie Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	34
Den Norske [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	16
Nextera [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	9
Toronto Dominion [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 4

Exploratory Well Costs (Capital

Exploratory Well Costs (Capitalized Exploratory Well And Project Activity) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized Exploratory Well Costs, Beginning Balance		$ 305	$ 159	$ 213
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves		1,178	1,860	1,220
Reclassification due to determination of proved reserves		(1,160)	(1,628)	(1,045)
Capitalized Exploratory Well Cost Assets Disposition		0	(47)	(93)
Impairment of oil and gas properties		1,056	0	1,495
Exploratory well costs charged to exploration expense	[1]	(17)	(26)	(49)
Capitalized Exploratory Well Costs, Ending Balance		306	305	159
Exploration Abandonment and Impairment Expense		99	177	97
Discontinued Operations [Member]
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Impairment of oil and gas properties	[2]		305	729
Capitalized exploratory costs [Member]
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Impairment of oil and gas properties		$ 0	$ (13)	(87)
Capitalized exploratory costs [Member] | Discontinued Operations [Member]
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Exploration Abandonment and Impairment Expense				$ 43
[1]	Includes exploration and abandonment expense of $43 million in 2013 that is included in discontinued operations in the accompanying consolidated statements of operations.
[2]	(b)Costs and expenses during 2015 were primarily related to an arbitration award associated with plugging and abandonment obligations for two Gulf of Mexico wells from which Pioneer withdrew in 2009. The Company incurred noncash impairment charges of $305 million and $729 million during the years ended December 31, 2014 and 2013, respectively, on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 and 2013 also included oil and gas production costs of $60 million and $117 million, respectively. See Note D for additional information regarding the noncash impairment charges related to the Hugoton assets, the Barnett Shale assets and Pioneer Alaska.

Exploratory Well Costs (Capit59

Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)
One year or less	$ 303	$ 305	$ 116
More than one year	3	0	43
Capitalized exploratory well costs, total suspended	$ 306	$ 305	$ 159	$ 213
Number of projects with exploratory well costs that have been suspended for a period greater than one year	1	0	1
Oooguruk [Member]
More than one year			$ 43

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Line of credit facility, maximum borrowing capacity		$ 1,500
Outstanding borrowings under the Credit Facility		0
Borrowings under long-term debt		998	$ 523	$ 467
Debt instrument, Unamortized Discount and Fee Amounts		$ 35	$ 41
Pioneer Credit Facility [Member]
Federal fund rate		0.50%
Alternate base rate spread		0.50%
Applicable margin		1.50%
Letters of credit outstanding under the Credit Facility, interest percentage		0.125%
Unused portion, fee percentage		0.20%
Swing Line Loans [Member] | Pioneer Credit Facility [Member]
Maximum outstanding borrowings under the Credit Facility		$ 150
2.875% Convertible Senior Notes Due 2038 [Member]
Senior Notes, interest rate, percentage		2.875%
Convertible debt					$ 480
Principal amount of notes tendered for conversion	$ 479
Cash Paid To Conversion Of Convertible Senior Notes	$ 479
Shares received for conversion of debt	4.4
Cash Paid To Redeem Convertible Debt	$ 1
Interest expense relating to the contractual interest coupon and unamortized discount				$ 9
Debt instrument, effective interest rate, percentage			6.75%
3.45% Senior Notes Due 2021 [Member]
Issuance of senior notes		$ 500	$ 0
Senior Notes, interest rate, percentage		3.45%
4.45% Senior Notes Due 2022 [Member]
Issuance of senior notes		$ 500	$ 0
Senior Notes, interest rate, percentage		4.45%
Combined 3.45% and 4.45% Senior Notes [Member]
Borrowings under long-term debt		$ 991
Debt instrument, Unamortized Discount and Fee Amounts		$ 9
Total Debt To Book Capitalization [Member] | Pioneer Credit Facility [Member]
Debt instrument covenant description		.60

Long-Term Debt (Components Of L

Long-Term Debt (Components Of Long-Term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Outstanding debt principal balances, gross	$ 3,690	$ 2,690
Issuance discounts and premiums, net	(35)	(41)
Net deferred fair value hedge losses	0	(1)
Long-term Debt	3,655	2,648
Outstanding borrowing	0
Long-term Debt, Current Maturities	448	0
Long-term Debt, Excluding Current Maturities	3,207	2,648
5.875% Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	455	455
Issuance discounts and premiums, net	$ (7)
Senior notes, interest rate	5.875%
6.65% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 485	485
Senior notes, interest rate	6.65%
6.875% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 450	450
Senior notes, interest rate	6.875%
7.500% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 450	450
Senior notes, interest rate	7.50%
3.45% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 500	0
Senior notes, interest rate	3.45%
3.95% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 600	600
Senior notes, interest rate	3.95%
4.45% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 500	0
Senior notes, interest rate	4.45%
7.20% Senior Notes Due 2028 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 250	$ 250
Senior notes, interest rate	7.20%

Long-Term Debt (Principal Matur

Long-Term Debt (Principal Maturities Of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
2,016	$ 455
2,017	485
2,018	450
2,019	0
2,020	450
Thereafter	$ 1,850

Long-Term Debt (Interest Expens

Long-Term Debt (Interest Expenses) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash payments for interest	$ 148	$ 193	$ 183
Accretion/amortization of discounts or premiums on loans	13	12	12
Amortization of capitalized loan fees	5	5	5
Net changes in accruals	25	(22)	(6)
Interest incurred	191	188	194
Less capitalized interest	(4)	(4)	(10)
Interest	$ 187	$ 184	$ 184

Incentive Plans (Narrative) (De

Incentive Plans (Narrative) (Details) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)$ / sharesRateshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Matching contributions vesting period in years		4
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 112	$ 110	$ 112
Unrecognized share-based compensation expense		$ 108
Restricted Units Vesting Schedule		3 years
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares		7,495
Employee Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 2	2	2
Employee stock purchase plan contribution limit | Rate		15.00%
Employee stock purchase plan participants purchase price percent | Rate		15.00%
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares		416,922
Approved and authorized awards | shares		1,250,000
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 22	$ 28	40
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares		271,031	328,087
Unrecognized share-based compensation expense		$ 17
Number of Shares granted | shares		161,692
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 23	$ 38	26
Amount of liabilities attributable to liability awards included in accounts payable		$ 16	23
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares granted | shares		603,169
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 70	$ 65	$ 57
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares		1,081,650	1,233,539
Number of Shares granted | shares		441,477
Number of unvested shares | shares			128,002
Weighted Average Grant-Date Fair Value, Shares granted | $ / shares		$ 153.55	$ 184.39	$ 134.17
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 66	$ 88	$ 69
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	[1]	$ 0	2	3
Option awards contract life		10
Average dividend yield		7
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercised, Intrinsic Value			$ 12	$ 21
Performance Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Grant-Date Fair Value, Shares granted | $ / shares		$ 222.33	$ 232.20	$ 189.23
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 17	$ 13	$ 19
Pioneer Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares		2,082,001
Approved and authorized awards | shares		9,100,000
Deferred Compensation Retirement Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Matching contributions percent | Rate		100.00%
Matching contributions		$ 3	3	3
Deferred Compensation Retirement Plan [Member] | Base Salary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants annual salary contributions, percentage | Rate		25.00%
Deferred Compensation Retirement Plan [Member] | Bonus [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants annual salary contributions, percentage | Rate		100.00%
401(k) Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants annual salary contributions, percentage | Rate		80.00%
Matching contributions percent | Rate		200.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay | Rate		5.00%
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 31	$ 33	$ 30
Officer [Member] | Deferred Compensation Retirement Plan [Member] | Base Salary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay | Rate		10.00%
Key Employee [Member] | Deferred Compensation Retirement Plan [Member] | Bonus [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay | Rate		8.00%
[1]	(a)Cash proceeds received from stock option exercises during 2014 and 2013 amounted to $6 million and $5 million, respectively. There were no stock option exercises during 2015.

Incentive Plans (Number Of Shar

Incentive Plans (Number Of Shares Available Under The Company's Long Term Incentive Plan) (Details) - Pioneer Long-Term Incentive Plan [Member]	116 Months Ended
	Dec. 31, 2015shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	9,100,000
Shares issued	(7,017,999)
Awards available for future grant	2,082,001

Incentive Plans (Schedule Of Em

Incentive Plans (Schedule Of Employee Stock Purchase Plan) (Details) - Employee Stock [Member]	228 Months Ended
	Dec. 31, 2015shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized shares	1,250,000
Shares issued	(833,078)
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	416,922

Incentive Plans (Schedule of Co

Incentive Plans (Schedule of Compensation Expense for Each Type of Incentive Award) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 112	$ 110	$ 112
Income Tax (Expense) Benefit		155	(556)	213
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Including Stock Options			6	5
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		70	65	57
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		22	28	40
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	[1]	0	2	3
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		18	13	9
Employee Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		2	2	2
Other Incentive Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		0	0	1
Compensation Expense For Incentive Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income Tax (Expense) Benefit		$ 34	$ 33	$ 36
[1]	(a)Cash proceeds received from stock option exercises during 2014 and 2013 amounted to $6 million and $5 million, respectively. There were no stock option exercises during 2015.

Incentive Plans (Schedule Of Re

Incentive Plans (Schedule Of Restricted Stock Award Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year	1,233,539
Number of Shares granted	441,477
Forfeitures, number of shares	(46,429)
Awards vested	(546,937)
Number of Shares/Units, Outstanding at end of year	1,081,650	1,233,539
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year	$ 140.57
Weighted Average Grant-Date Fair Value, Shares granted	153.55	$ 184.39	$ 134.17
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	155.52
Weighted Average Grant-Date Fair Value, Shares vested	138.76
Weighted Average Grant-Date Fair Value, Outstanding at end of year	$ 151.50	$ 140.57
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year	328,087
Number of Shares granted	161,692
Forfeitures, number of shares	(33,082)
Awards vested	(185,666)
Number of Shares/Units, Outstanding at end of year	271,031	328,087

Incentive Plans (Schedule Of St

Incentive Plans (Schedule Of Stock Options Awards Activity) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options exercised	(58,000)	(130,000)	(222,000)
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares, Outstanding at beginning of year	199,058
Options exercised	0
Number of Shares, Outstanding and expected to vest at end of year	199,058	199,058
Number of Shares, Exercisable at end of year	199,058
Weighted Average Exercise Price, Outstanding at beginning of year	$ 77.51
Weighted Average Exercise Price, Options exercised	0
Weighted Average Exercise Price, Outstanding and expected to vest at end of year	77.51	$ 77.51
Weighted Average Exercise Price, Exercisable at end of year	$ 77.51
Weighted Average Remaining Contractual Life, Outstanding and expected to vest at end of year	4 years 11 months 15 days
Weighted Average Remaining Contractual Life, Exercisable at end of year	4 years 11 months 15 days
Aggregate Intrinsic Value, Outstanding and expected to vest at end of year	$ 10
Aggregate Intrinsic Value, Exercisable at end of year	$ 10

Incentive Plans (Schedule Of As

Incentive Plans (Schedule Of Assumptions To Estimate The Fair Value) (Details) - Performance Units [Member]	12 Months Ended
	Dec. 31, 2015Rate	Dec. 31, 2014Rate	Dec. 31, 2013Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.03%	0.62%	0.40%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	41.30%	41.50%	42.90%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	26.10%	29.00%	30.40%

Incentive Plans (Schedule Of Pe

Incentive Plans (Schedule Of Performance Unit Activity) (Details) - $ / shares		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares issued		152,775,920	152,158,428
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year	[1]	154,733
Number of Units granted	[1]	82,431
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	[1]	0
Awards vested	[1],[2]	(87,551)
Number of Shares/Units, Outstanding at end of year	[1]	148,547	154,733
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year		$ 207.88
Weighted Average Grant-Date Fair Value, Units granted		222.33
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		0
Weighted Average Grant Date Fair Value, Units vested	[2]	189.71
Weighted Average Grant-Date Fair Value, Outstanding at end of year		$ 226.74	$ 207.88
Performance percentage of actual payout minimum		0.00%
Performance percentage to reach maximum		250.00%
Number of shares earned for each vested award		1.5
Common stock, shares issued		132,566
Performance Units, including Retirement Deferred Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested	[1],[2]	(88,617)
Retirement Deferred Performance Units [Member] [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested	[1],[2]	(1,066)
Performance Units Service Period Lapsed [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested		(88,374)
Retirement Deferred Performance Units Service Period Lapse [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested		(823)
[1]	(a)These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date.
[2]	(b)Of the 88,617 units that vested during 2015, 87,551 units vested according to the scheduled timing of the associated award and 1,066 units, which were originally scheduled to vest in 2016 and 2017, vested upon retirement of the officer to whom the performance unit awards were granted. On December 31, 2015, the service period lapsed on 88,374 performance unit awards that earned 1.5 shares for each vested award, representing 132,566 aggregate shares of common stock issued on January 4, 2016. The vested performance units that earned 1.5 shares for each vested award included 87,551 units vested in the current year and 823 units that vested in 2014 upon the retirement of the officer to whom the performance unit awards were granted.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance		$ 189	$ 194	$ 198
AssetRetirementObligationLiabilitiesAcquiredInBusinessCombination		0	6	0
Liabilities incurred		4	5	6
Changes in estimates	[1]	103	7	8
Disposition of wells		0	(14)	(16)
Liabilities settled		(23)	(21)	(15)
Accretion of discount on continuing operations		12	12	12
Accretion of discount on discontinued operations		0	0	1
Asset Retirement Obligations, Ending Balance		285	189	$ 194
Asset retirement obligations, current portion		$ 40	$ 28
[1]	(a)Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The increase in 2015 is primarily due to the forecasted timing of abandoning the Company's oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company's producing wells.

Commitments And Contingencies73

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Current annual salaries of officers and key employees	$ 35

Commitments And Contingencies C

Commitments And Contingencies Commitments and Contingencies (Future Minimum Drilling Commitments) (Details) $ in Millions	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Other Commitment, Due in Next Twelve Months	$ 179
Other Commitment, Due in Second Year	110
Other Commitment, Due in Third Year	64
Other Commitment, Due in Fourth Year	10
Other Commitment, Due in Fifth Year	0
Other Commitment, Due Thereafter	$ 0

Commitments And Contingencies75

Commitments And Contingencies (Future Minimum Lease Commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies [Line Items]
Operating Leases, Rent Expense	$ 58	$ 66	$ 58
Operating Leases, Future Minimum Payments Due	7
Restructuring Reserve	4
Year 1 Minimum Lease Commitments	24
Year 2 Minimum Lease Commitments	23
Year 3 Minimum Lease Commitments	21
Year 4 Minimum Lease Commitments	21
Year 5 Minimum Lease Commitments	17
Thereafter	15
Lease Payments Discontinued Operations [Member]
Commitments And Contingencies [Line Items]
Operating Leases, Rent Expense		$ 9	$ 10
Colorado [Member]
Commitments And Contingencies [Line Items]
Restructuring Reserve	$ 3

Commitments And Contingencies76

Commitments And Contingencies (Future Minimum Transportation Fees) (Details) $ in Millions	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Year 1 Transportation Agreements	$ 451
Year 2 Transportation Agreements	479
Year 3 Transportation Agreements	476
Year 4 Transportation Agreements	467
Year 5 Transportation Agreements	465
Thereafter	$ 1,145

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue from Related Parties		$ 3	$ 3
Proceeds from Equity Method Investment, Dividends or Distributions	$ 0	50	25
EFS Midstream [Member]
Cost reimbursement fixed	2	3	3
Cost reimbursement variable	9	18	16
Payments to Acquire Property, Plant, and Equipment			3
Gathering And Treating Fees [Member] | EFS Midstream [Member]
Related party transaction expenses paid	$ 54	$ 103	$ 81

Major Customers (Consolidated O

Major Customers (Consolidated Oil, NGL And Gas Revenues) (Details) - Oil And Gas Revenue [Member]	12 Months Ended
	Dec. 31, 2015Rate	Dec. 31, 2014Rate	Dec. 31, 2013Rate
Plains Marketing LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	22.00%	29.00%	28.00%
Occidental Energy Marketing Inc [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	16.00%	13.00%
Vitol, Inc. [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	9.00%	5.00%
Enterprise Products Partners L.P. [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%	13.00%	13.00%

Major Customers Major Customers

Major Customers Major Customers (Sales of Purchased Oil and Gas (Details) - Sales of Purchased Oil and Gas [Member]	12 Months Ended
	Dec. 31, 2015Rate	Dec. 31, 2014Rate	Dec. 31, 2013Rate
Valero Marketing and Supply Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	37.00%	61.00%	51.00%
Occidental Energy Marketing Inc [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	0.00%	1.00%
Plains Marketing LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	0.00%	0.00%
EDF Trading North America [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	4.00%	9.00%	20.00%

Interest And Other Income (Inte

Interest And Other Income (Interest And Other Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest and Other Income [Abstract]
Equity interest in income (loss) of EFS Midstream	$ 5	$ 13	$ 7
Deferred compensation plan income	4	3	6
Interest income	3	0	0
Other income	10	10	10
Total interest and other income	$ 22	$ 26	$ 23

Other Expense (Schedule Of Comp

Other Expense (Schedule Of Components Of Other Expense) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Idle Rig Expense		$ 92	$ 7	$ 10
Tangible Asset Impairment Charges	[1]	86	8	62
Transportation commitment charge	[2]	53	46	39
Third-party income (loss) from vertical integration services		34	16	5
Restructuring and Related Cost, Incurred Cost		23	0	0
Contingency and environmental accrual adjustments		0	0	9
Other		27	29	18
Total other expense		315	106	143
GrossRevenuesIncludedInThirdPartyIncomeFromVerticalIntegrationServices		298	374	285
GrossExpensesIncludedInThirdPartyIncomeFromVerticalIntegrationServices		332	390	290
Inventory [Member]
Tangible Asset Impairment Charges		$ 71	$ 8	36
Sendero [Member]
Tangible Asset Impairment Charges				$ 25
[1]	(c)Primarily represents firm transportation payments on excess pipeline capacity commitments.
[2]	Primarily represents expenses attributable to idle drilling rig fees which are not chargeable to joint operations.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Payments for income taxes, net of tax refunds received	$ 43	$ 22	$ 12
Unrecognized tax benefit recognized in period	$ 0	$ 21	$ 0

Income Taxes (Summary Of Open T

Income Taxes (Summary Of Open Tax Years, By Jurisdiction) (Details)	12 Months Ended
	Dec. 31, 2015
UNITED STATES
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,014
Various U.S. States [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,010
South Africa [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,010

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax (Provision) Benefit Allocation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income tax benefit (provision)	$ 155	$ (556)	$ 213
Income tax from discontinued operations	2	60	249
Tax benefits related to stock-based compensation	7	19	18
Income Tax Effects Allocated Directly to Equity, Equity Transactions	0	0	38
Deferred tax benefit associated with the Pioneer Southwest merger	$ 0	$ 0	$ 200

Income Taxes (Income Tax (Provi

Income Taxes (Income Tax (Provision) Benefit Attributable To Income From Continuing Operations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
U.S. federal	$ (22)	$ (3)	$ (11)
U.S. state	(1)	(1)	0
Current income tax (provision) benefit	(23)	(4)	(11)
U.S. federal	165	(537)	208
U.S. state	13	(15)	16
Deferred income tax (provision) benefit	178	(552)	224
Income tax (provision) benefit	$ 155	$ (556)	$ 213

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	$ (421)	$ 1,597	$ (574)
Net Income Attributable to Noncontrolling Interest	0	0	(39)
Income (loss) from continuing operations before tax	$ (421)	$ 1,597	$ (613)
U.S. federal statutory tax rate	35.00%	35.00%	35.00%
Income Tax Reconciliation, Income Tax (Expense) Benefit, at Federal Statutory Income Tax Rate	$ 147	$ (559)	$ 215
Income Tax Reconciliation, State and Local Income Taxes	8	(10)	10
Unrecognized tax benefit recognized in period	0	21	0
Income Tax Reconciliation, Other Adjustments	0	(8)	(12)
Income Tax (Expense) Benefit	$ 155	$ (556)	$ 213
Effective Income Tax Rate, Continuing Operations	37.00%	35.00%	35.00%

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Deferred Tax Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Valuation Allowance [Line Items]
Net operating loss carryforward	[1]	$ 441	$ 330
Asset retirement obligations		102	68
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost		75	71
Other		102	74
Total deferred tax assets		720	543
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes		(1,997)	(1,881)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes		(227)	(251)
Net deferred hedge gains		(272)	(280)
State taxes and other		0	(95)
Total deferred tax liabilities		(2,496)	(2,507)
Deferred Tax Liabilities, Net		(1,776)	$ (1,964)
UNITED STATES
Valuation Allowance [Line Items]
Net operating loss carryforward		1,200
COLORADO
Valuation Allowance [Line Items]
Net operating loss carryforward		$ 132
[1]	Net operating loss carryforwards as of December 31, 2015 consist of $1.2 billion of U.S. federal NOLs which expire primarily between 2032 and 2035 and $132 million of Colorado NOLs which expire between 2028 and 2034

Net Income (Loss) Per Share A88

Net Income (Loss) Per Share Attributable To Common Stockholders (Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement Operating Activities Segment [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic		$ (273)	$ 920	$ (838)
Diluted income (loss) attributable to common stockholders		(273)	920	(838)
Segment, Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations, net of tax		(266)	1,041	(400)
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic	[1]	0	(10)	0
Net Income (Loss) Available to Common Stockholders, Basic		(266)	1,031	(400)
Diluted income (loss) attributable to common stockholders		(266)	1,031	(400)
Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic		(7)	(111)	(438)
Diluted income (loss) attributable to common stockholders		$ (7)	$ (111)	$ (438)
[1]	(a)Unvested restricted stock awards and Pioneer Southwest phantom unit awards (prior to the December 2013 Pioneer Southwest merger) represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

Net Income (Loss) Per Share A89

Net Income (Loss) Per Share Attributable To Common Stockholders (Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding) (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Basic	149	144	136
Diluted	149	144	136

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) shares in Thousands, $ in Millions	2 Months Ended	12 Months Ended
	Feb. 18, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsequent Event [Line Items]
Stock Issued During Period, Shares, New Issues			5,750	10,350
Proceeds from Issuance of Common Stock		$ 0	$ 980	$ 1,281
Subsequent Event [Member]
Subsequent Event [Line Items]
Stock Issued During Period, Shares, New Issues	13,800
Proceeds from Issuance of Common Stock	$ 1,600
Minimum [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Restructuring and Related Cost, Expected Cost	10
Maximum [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Restructuring and Related Cost, Expected Cost	$ 20