Pioneer Natural Resources (PXD) 10-K 17 Feb 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 13, 2017	Jun. 30, 2016
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, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		169,796,963
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 25,469,484,123

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 1,118	$ 1,391
Short-term Investments		1,441	0
Accounts receivable:
Trade, net		517	384
Due from affiliates		1	1
Income taxes receivable		3	43
Inventories		181	155
Notes receivable		0	498
Other current assets:
Derivatives		14	694
Other		23	28
Total current assets		3,298	3,194
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		18,566	16,631
Unproved properties		486	169
Accumulated depletion, depreciation and amortization		(8,211)	(6,778)
Total property, plant and equipment		10,841	10,022
Long-term Investments		420	0
Goodwill		272	272
Property, Plant and Equipment, Net	[1]	1,529	1,523
Other assets:
Derivatives		0	64
Other, net		99	79
Assets, Total		16,459	15,154
Accounts payable:
Trade		741	798
Due to affiliates		134	85
Interest payable		68	65
Income taxes payable		0	2
Other current liabilities:
Long-term Debt, Current Maturities		485	448
Derivatives		77	0
Other		61	64
Total current liabilities		1,566	1,462
Long-term Debt, Excluding Current Maturities		2,728	3,207
Derivatives		7	1
Deferred income taxes		1,397	1,776
Other liabilities		350	333
Stockholders' equity:
Common stock, $.01 par value		2	2
Additional paid-in capital		8,892	6,267
Treasury stock, at cost		(218)	(199)
Retained earnings		1,728	2,298
Total stockholders' equity attributable to common stockholders		10,404	8,368
Noncontrolling interest in consolidating subsidiaries		7	7
Total stockholders' equity		10,411	8,375
Liabilities and Stockholders' Equity, Total		$ 16,459	$ 15,154
[1]	At December 31, 2016 and 2015, other property and equipment was net of accumulated depreciation of $866 million and $711 million, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	173,221,845	152,775,920
Treasury stock, shares	3,497,742	3,396,220

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues and other income:
Oil and Gas Revenue	$ 2,418	$ 2,178	$ 3,599
Sales of purchased oil and gas	1,533	964	726
Interest and other	32	22	26
Derivative gains, net	(161)	879	712
Gain on disposition of assets, net	2	782	9
Revenues	3,824	4,825	5,072
Costs and expenses:
Oil and Gas Production Expense	581	717	693
Production and ad valorem taxes	136	145	220
Depletion, depreciation and amortization	1,480	1,385	1,047
Purchased oil and gas	1,597	1,003	703
Impairment of oil and gas properties	32	1,056	0
Exploration and abandonments	119	99	177
General and administrative	325	327	333
Accretion of discount on asset retirement obligations	18	12	12
Interest	207	187	184
Other	288	315	106
Costs and expenses, Total	4,783	5,246	3,475
Income (loss) from continuing operations before income taxes	(959)	(421)	1,597
Income tax benefit (provision)	403	155	(556)
Income (loss) from continuing operations	(556)	(266)	1,041
Loss from discontinued operations, net of tax	0	(7)	(111)
Net income (loss)	(556)	(273)	930
Net income (loss) attributable to common stockholders	$ (556)	$ (273)	$ 930
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ (3.34)	$ (1.79)	$ 7.17
Loss from discontinued operations attributable to common stockholders	0	(0.04)	(0.77)
Net income (loss) attributable to common stockholders	(3.34)	(1.83)	6.40
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	(3.34)	(1.79)	7.15
Loss from discontinued operations attributable to common stockholders	0	(0.04)	(0.77)
Net income (loss) attributable to common stockholders	$ (3.34)	$ (1.83)	$ 6.38
Weighted average shares outstanding:
Basic	166	149	144
Diluted	166	149	144
Amounts attributable to common stockholders:
Net income (loss) attributable to common stockholders	$ (556)	$ (273)	$ 930

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]
Beginning Balance at Dec. 31, 2013	$ 6,615	$ 1	$ 5,080	$ (144)	$ 1,665	$ 13
Beginning 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)
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)		0
Tax benefits related to stock-based compensation	$ 7		7
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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, New Issues	19,840
Issuance of Common Stock	$ 2,534	0	2,534
Dividends declared ($0.08 per share)	$ (14)				(14)
Exercise of long-term incentive plan stock options and employee stock purchases, shares	98
Exercise of long-term incentive plan stock options and employee stock purchases	$ 7		1	6	0
Purchase of treasury stock, shares	(200)
Purchase of treasury stock	$ (25)			(25)
Tax benefits related to stock-based compensation	$ 1		1
Compensation costs:
Vested compensation awards, net, shares	608
Vested compensation awards, net	$ 0	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition	89		89			0
Net income (loss)	(556)				(556)	0
Ending Balance at Dec. 31, 2016	$ 10,411	$ 2	$ 8,892	$ (218)	$ 1,728	$ 7
Ending Balance, shares at Dec. 31, 2016	169,724

Consolidated Statements Of Sto6

Consolidated Statements Of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Income (Loss) Attributable to Parent	$ (556)	$ (273)	$ 930
Cash flows from operating activities:
Net income (loss)	(556)	(273)	930
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	1,480	1,385	1,047
Impairment of oil and gas properties	32	1,056	0
Impairment of inventory and other property and equipment	8	86	8
Exploration expenses, including dry holes	42	28	90
Deferred income taxes	(379)	(178)	552
Gain on disposition of assets, net	(2)	(782)	(9)
Accretion of discount on asset retirement obligations	18	12	12
Discontinued operations	0	(4)	251
Interest expense	13	18	17
Derivative related activity	851	(3)	(609)
Amortization of stock-based compensation	89	90	84
Other	66	38	34
Change in operating assets and liabilities
Accounts receivable, net	(134)	54	(29)
Income taxes receivable	40	(20)	(18)
Inventories	(32)	8	(37)
Increase (Decrease) in Derivative Assets and Liabilities	(24)	0	0
Increase Decrease in Investments	(22)	0	0
Other current assets	(7)	0	(2)
Accounts payable	58	(258)	104
Interest payable	3	25	(22)
Income taxes payable	(2)	1	1
Other current liabilities	(44)	(35)	(38)
Net cash provided by operating activities	1,498	1,248	2,366
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	507	553	877
Business acquisition	(428)	0	0
Proceeds from investments	902	0	0
Purchase of investments	(2,741)	0	0
Additions to oil and gas properties	(1,857)	(2,110)	(3,243)
Additions to other assets and other property and equipment, net	(203)	(283)	(333)
Net cash used in investing activities	(3,820)	(1,840)	(2,699)
Cash flows from financing activities:
Borrowings under long-term debt	0	998	523
Principal payments on long-term debt	(455)	0	(523)
Proceeds from Issuance of Common Stock	2,534	0	980
Distributions to noncontrolling interests	0	(1)	(1)
Exercise of long-term incentive plan stock options and employee stock purchases	7	6	13
Purchase of treasury stock	(25)	(31)	(34)
Excess tax benefits from share-based payment arrangements	1	7	19
Payment of financing fees	0	(9)	0
Dividends paid	(13)	(12)	(12)
Net cash provided by financing activities	2,049	958	965
Net increase (decrease) in cash and cash equivalents	(273)	366	632
Cash and cash equivalents	1,118	1,391	1,025
Cash and cash equivalents, end of period	$ 1,118	$ 1,391	$ 1,025

Organization And Nature Of Oper

Organization And Nature Of Operations	12 Months Ended
	Dec. 31, 2016
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 that explores for, develops and produces oil, NGLs and gas within 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.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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 2015 and 2014 financial statement and footnote amounts in order to conform them to the 2016 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. Investments. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates. Accounts receivable. As of December 31, 2016 and 2015 , the Company had accounts receivable – trade, net of allowances for bad debts, of $517 million and $384 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, 2016 and 2015 , 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, 2016 and 2015 : As of December 31, 2016 2015 (in millions) Materials and supplies (a) $ 144 $ 132 Commodities 37 23 $ 181 $ 155 ____________________ (a) As of December 31, 2016 and 2015 , the Company's materials and supplies inventories were net of valuation allowances of $28 million and $78 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 eight gas processing plants and nine treating facilities. The Company is the operator of one of the gas processing plants and all nine of the treating facilities. Seven 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, 2016 , 2015 and 2014 were $41 million , $39 million and $56 million , respectively. Third party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $24 million , $27 million and $24 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 2016 , the Company performed its annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step impairment test. Based on the results of the assessment, the Company determined it was not likely that the Company's goodwill was impaired. Other property and equipment, net. Other property and equipment is recorded at cost. As of December 31, 2016 and 2015 , the net carrying value of other property and equipment consisted of the following: As of December 31, 2016 (a) 2015 (a) (in millions) Proved and unproved sand properties (b) $ 484 $ 473 Land and buildings 475 468 Equipment and rigs (c) 206 287 Water infrastructure (d) 221 180 Vehicles 15 21 Furniture and fixtures 22 24 Information technology (e) 84 43 Leasehold improvements 22 27 $ 1,529 $ 1,523 ____________________ (a) At December 31, 2016 and 2015 , other property and equipment was net of accumulated depreciation of $866 million and $711 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 pressure pumping and well services on Company-operated properties. As of December 31, 2016 , 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. (e) Information technology costs include hardware and software costs associated with the Company's existing systems and in-progress system upgrades. The primary purpose of the Company's sand mine, pressure pumping, well services and water infrastructure operations is to accommodate the Company's drilling, completion and production 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 mine, pressure pumping, well services and water infrastructure 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. 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 June 2016, January 2016 and November 2014, the Company issued 6.0 million , 13.8 million and 5.75 million shares of its common stock, respectively, and realized cash proceeds of $937 million , $1.6 billion and $980 million , respectively, net of associated underwriting and offering expenses. 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 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 oil ("WTI") 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. Income taxes. 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. As of December 31, 2016 , the Company had unrecognized tax benefits of $112 million resulting from research and experimental expenditures related to horizontal drilling and completion innovations. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. See Note O for additional information regarding uncertain tax positions. 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 fair value of the vested portion 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. Restructuring. In February 2016, the Company announced plans to restructure its pressure pumping operations in South Texas, including relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. In connection therewith, the Company offered severance to certain employees and relocated a number of other employees from its South Texas locations to its operations in the Permian Basin. The initiative was substantially complete as of December 31, 2016. In connection therewith, during the year ended December 31, 2016 , the Company recognized $4 million of restructuring charges in other expense in the accompanying consolidated statements of operations. The restructuring costs included $3 million in cash employee severance costs and $1 million in employee relocation and other costs. 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 pressure 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. The $17 million of employee severance costs for the year ended December 31, 2015 included $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 for the year ended December 31, 2015 related to certain Denver office space that will no longer be used, of which $2 million represented the impairment of leasehold improvements and $4 million represented the Company's future obligations under the operating leases, net of anticipated sublease income. As of December 31, 2016 and 2015 , the Company had $2 million and $4 million , respectively, 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. In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-04, "Simplifying the Test of Goodwill Impairment." ASU 2017-04 simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill (Step 2 of the current goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit's carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard's provisions prospectively. Based on the Company's qualitative assessments of goodwill for impairment during the third quarter and fourth quarter of 2016 and 2015, respectively, the Company does not believe this standard will have a material quantitative effect on the consolidated financial statements; however, this standard will change the policy under which the Company performs its annual impairment assessment by eliminating Step 2 of the test. In June 2016, the FASB issued ASU 2016-13, "Measurement of Credit Losses on Financial Instruments." ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company does not believe this standard will have a material impact on its consolidated financial statements. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Company does not believe this standard will have a material impact on its consolidated financial statements. In February 2016, FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have 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. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified approach to adopt the new standards and the Company plans to utilize the modified approach to adopt the new standard upon its effective date. The Company is evaluating the new guidance, including identification of revenue streams and review of contracts and procedures currently in place. The Company does not anticipate this standard will have a material impact on its consolidated financial statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisition and Divestitures [Text Block]	NOTE C. Acquisitions and Divestitures Acquisitions Permian Basin. In August 2016, the Company acquired approximately 28,000 net acres in the Permian Basin, with net production of approximately 1,400 barrels of oil equivalent per day ("BOEPD"), from an unaffiliated third party for $428 million , including normal closing adjustments. The acquisition was accounted for using the acquisition method under ASC 805, "Business Combinations," which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date. The following table represents the preliminary allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date, pending final post-closing adjustments (in millions): Assets acquired: Proved properties $ 79 Unproved properties 347 Other property and equipment 5 Liabilities assumed: Asset retirement obligations (2 ) Other liabilities (1 ) Net assets acquired $ 428 The fair value measurements of the net assets acquired are based on inputs that are not observable in the market and, therefore, represent Level 3 inputs in the fair value hierarchy (see Note D for a description of the input levels in the fair value hierarchy). The Company calculated the fair values of the acquired proved properties and asset retirement obligations using a discounted future cash flow model that utilizes management's estimates of (i) proved reserves, (ii) forecasted production rates, (iii) future operating, development and plugging and abandonment costs, (iv) future commodity prices and (v) a discount rate of 10 percent for proved properties and seven percent for asset retirement obligations. The Company calculated the fair values of the acquired unproved properties based on the average price per acre in comparable market transactions. In connection with the acquisition, the Company incurred acquisition related costs (primarily consulting, advisory and legal fees) of approximately $1 million . The operating results included in the Company's accompanying consolidated statements of operations from the date of acquisition to December 31, 2016, and the operating results that would have been recognized had the acquisition occurred on January 1, 2016, are not material to the Company's accompanying consolidated statements of operations. Affiliated Partnerships. In December 2014, the Company acquired the remaining limited partner interests in five affiliated oil and gas drilling partnerships for $54 million and caused the partnerships to be merged with and into a wholly-owned subsidiary of the Company. Divestitures Recorded in Continuing Operations The Company recorded net gains on the disposition of assets in continuing operations of $2 million , $782 million and $9 million during the years ended December 31, 2016 , 2015 and 2014 , 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 LLC ("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 $501 million was received in July 2016. Associated with the sale, the Company recorded a pretax gain of $777 million during 2015. • Vertical drilling rigs. In March 2014, the Company completed the sale of its majority interest in Sendero Drilling Company, LLC ("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, 2016, 2015 and 2014, the Company incurred $28 million , $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. In 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 . • Other. During 2016 , 2015 and 2014 , the Company sold other proved and unproved properties, inventory and other property and equipment and recorded net gains of $2 million , $5 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 . Barnett Shale. In September 2014, the Company completed the sale of its Barnett Shale net assets for cash proceeds of $150 million . 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 . The following table represents the components of the Company's discontinued operations for the years ended December 31, 2015 and 2014 . The Company did not recognize any income or loss from discontinued operations in 2016. Year Ended December 31, 2015 2014 (in millions) Revenues and other income (a) $ 1 $ 238 Costs and expenses (b) 10 409 Loss from discontinued operations before income taxes (9 ) (171 ) Current tax provision (1 ) — Deferred tax benefit 3 60 Loss from discontinued operations, net of tax $ (7 ) $ (111 ) ____________________ (a) Revenues and other income for the year ended December 31, 2014 was primarily comprised of oil and gas revenues of $198 million . (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 during the year ended December 31, 2014 on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 also included oil and gas production costs of $60 million . 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, 2016
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, 2016 and 2015 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2016 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, 2016 (in millions) Assets: Commodity derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 6 — 6 Deferred compensation plan assets 83 — — 83 Total assets 83 14 — 97 Liabilities: Commodity derivatives — 84 — 84 Total liabilities — 84 — 84 Total recurring fair value measurements $ 83 $ (70 ) $ — $ 13 Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant 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 Commodity derivatives. The Company's commodity derivatives represent oil, NGL, gas and diesel 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 contracts 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, 2016 and 2015 , the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Interest rate derivatives. The Company's interest rate derivative assets as of December 31, 2016 represent interest rate swap contracts. As of December 31, 2015, the Company had no interest rate derivative assets or liabilities. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The derivative values attributable to the Company's interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) forward active market-quoted London Interbank Offered Rates ("LIBOR") and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset 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. See Note C for information on the fair value of assets and liabilities acquired in the Permian Basin acquisition. Inventories. During the years ended December 31, 2016 , 2015 and 2014 , the Company recognized noncash impairment charges of $8 million , $71 million and $8 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 West Panhandle field during the year ended December 31, 2016 and (ii) the Eagle Ford Shale field, the West Panhandle field and the South Texas - Other field during the year ended December 31, 2015. The Company calculated the fair values of the West Panhandle field, the Eagle Ford Shale field and the South Texas - Other 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 longer-term commodity price outlooks ("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 2016 and 2015 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 West Panhandle March 2016 $ 33 $ (32 ) $ 49.77 $ 3.24 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 It is reasonably possible that the Company's 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 reserves. 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. Pioneer Alaska and the Barnett Shale assets were classified as held for sale at December 31, 2013 and carried as such until their divestitures in 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. 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 year ended December 31, 2014 related to assets associated with divestitures: Year Ended December 31, 2014 Classification 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 ) Pioneer Alaska Discontinued operations $ 253 $ (97 ) Unproved oil and gas properties. During March 2016, the Company recorded an impairment charge of $32 million to write-off the carrying value of its unproved royalty acreage in Alaska (reported in exploration and abandonments in the accompanying consolidated statements of operations) as a result of the operator curtailing operations in the area and Management's Price Outlooks. During 2015 and 2014, the Company recorded impairment charges of $7 million and $50 million , respectively, 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, 2016 and 2015 are as follows: December 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 1,906 $ 1,901 $ 275 $ 275 Current portion of long-term debt $ 485 $ 490 $ 448 $ 462 Long-term debt $ 2,728 $ 2,956 $ 3,207 $ 3,206 Commercial paper, corporate bonds and time deposits. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. The investments are carried at amortized cost and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The net carrying value of held-to-maturity investments is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the investments. Income related to these investments is recorded in interest and other income in the Company's consolidated statement of operations. The Company's investments in corporate bonds represent Level 1 inputs in the hierarchy, while the other investments represent Level 2 inputs in the hierarchy. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates. The following table provides the components of the Company's cash and cash equivalents and investments as of December 31, 2016 : December 31, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 1,073 $ 45 $ — $ — $ 1,118 Short-term investments — 368 691 382 1,441 Long-term investments — — 420 — 420 $ 1,073 $ 413 $ 1,111 $ 382 $ 2,979 Debt obligations. 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. 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. 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 receivables, prepaid expenses, 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, 2016 , the Company's primary concentration of credit risks are the risks associated with collecting receivables (principally accounts 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, 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, 2016
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. Periodically, the Company may pay a premium to enter into commodity contracts. Premiums paid, if any, have been nominal in relation to the value of the underlying asset in the contract. The Company recognizes the nominal premium payments as an increase to the value of the derivative assets when paid. All derivatives are adjusted to fair value as of each balance sheet date. 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, 2016 and the weighted average oil prices for those contracts: 2017 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Collar contracts: Volume (Bbl) 6,000 6,000 6,000 6,000 — Average price per Bbl: Ceiling $ 70.40 $ 70.40 $ 70.40 $ 70.40 $ — Floor $ 50.00 $ 50.00 $ 50.00 $ 50.00 $ — Collar contracts with short puts (a): Volume (Bbl) 119,000 129,000 147,000 155,000 20,000 Price per Bbl: Ceiling $ 61.36 $ 61.19 $ 62.03 $ 62.12 $ 65.14 Floor $ 48.67 $ 48.46 $ 49.81 $ 49.82 $ 50.00 Short put $ 40.65 $ 40.45 $ 41.07 $ 41.02 $ 40.00 Rollfactor swap contracts (b): Volume (Bbl) 13,111 20,000 20,000 20,000 — NYMEX roll price $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ — Basis swap contracts: Midland-Cushing index swap volume (Bbl) — — — 3,000 740 Price differential ($/Bbl) (c) $ — $ — $ — $ (0.65 ) $ (0.65 ) _______________ (a) During the year ended December 31, 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl. (b) Represents swaps that fix the difference between (i) each day's price per Bbl of WTI for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. (c) Represents the basis differential between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma. NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu, Texas or Conway, Kansas 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, 2016 and the weighted average NGL prices for those contracts: 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Ethane collar contracts (a): Volume (Bbl) 3,000 3,000 3,000 3,000 Price per Bbl: Ceiling $ 11.83 $ 11.83 $ 11.83 $ 11.83 Floor $ 8.68 $ 8.68 $ 8.68 $ 8.68 Butane collar contracts with short puts (b): Volume (Bbl) — 2,000 2,000 — Price per Bbl: Ceiling $ — $ 36.12 $ 36.12 $ — Floor $ — $ 29.25 $ 29.25 $ — Short put $ — $ 23.40 $ 23.40 $ — ____________________ (a) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. (b) Represent collar contracts with short puts that reduce the price volatility of butane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. Subsequent to December 31, 2016, the Company entered into (i) 2,000 Bbls per day of butane swap contracts for April 2017 through September 2017 with a fixed price of $34.86 per Bbl and (ii) 6,920 MMBtu per day of ethane basis swap contracts for March 2017 through December 2019 with a fixed price of $1.60 per MMBtu. The basis swaps fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane. Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to 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, 2016 and the weighted average gas prices for those contracts: 2017 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Collar contracts with short puts (a): Volume (MMBtu) 190,000 190,000 190,000 190,000 57,397 Price per MMBtu: Ceiling $ 3.51 $ 3.51 $ 3.51 $ 3.51 $ 3.51 Floor $ 2.93 $ 2.93 $ 2.93 $ 2.93 $ 2.85 Short put $ 2.46 $ 2.46 $ 2.46 $ 2.46 $ 2.33 Basis swap contracts: Mid-Continent index swap volume (b) 45,000 45,000 45,000 45,000 — Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ — Permian Basin index swap volume (c) 40,000 — — — — Price differential ($/MMBtu) $ 0.37 $ — $ — $ — $ — ____________________ (a) Subsequent to December 31, 2016, the Company entered into additional gas collar contracts with short puts for 20,000 MMBtu per day of January 2018 through March 2018 production with a ceiling price of $4.20 per MMBtu, a floor price of $3.55 per MMBtu and a short put price of $2.85 per MMBtu. (b) Represents swaps that fix the basis differentials between the index prices at which the Company sells its Mid-Continent gas and the HH index price used in gas swap and collar contracts with short puts. (c) 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. 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, 2016 , the Company did not have any marketing derivatives outstanding. Diesel derivative activities. Periodically, the Company enters into diesel derivative swap contracts to mitigate fuel price risk. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment. During the fourth quarter of 2016, the Company terminated 2017 diesel swap contracts for 1,000 Bbls per day for cash proceeds of $2 million . As of December 31, 2016 , the Company does not have any diesel derivative contracts outstanding. Interest rate derivative activities. During the fourth quarter of 2016, the Company terminated interest rate derivative contracts on a notional amount of $150 million for cash proceeds of $7 million . As of December 31, 2016 , the Company was party to 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 1.81 percent on a notional amount of $100 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, 2016 and December 31, 2015 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, 2016 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 $ 33 $ (25 ) $ 8 Interest rate derivatives Derivatives - current $ 6 $ — 6 $ 14 Liability Derivatives: Commodity price derivatives Derivatives - current $ 102 $ (25 ) $ 77 Commodity price derivatives Derivatives - noncurrent $ 7 $ — 7 $ 84 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 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, 2016 2015 2014 (in millions) Commodity price derivatives Derivative gains (losses), net $ (174 ) $ 873 $ 697 Interest rate derivatives Derivative gains (losses), net 13 6 15 Total $ (161 ) $ 879 $ 712 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 or liabilities by counterparty as of December 31, 2016 : Net Assets (Liabilities) (in millions) JP Morgan Chase $ (19 ) Macquarie Bank (11 ) Societe Generale (9 ) BNP Paribas (7 ) Citibank, N.A. (6 ) J. Aron & Company (5 ) Toronto Dominion (5 ) Morgan Stanley (4 ) Nextera Energy (3 ) Merrill Lynch (2 ) Wells Fargo Bank, N.A. (2 ) Scotia Bank 3 Total $ (70 )

Exploratory Well Costs

Exploratory Well Costs	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Beginning capitalized exploratory well costs $ 306 $ 305 $ 159 Additions to exploratory well costs pending the determination of proved reserves 1,387 1,178 1,860 Reclassification due to determination of proved reserves (1,369 ) (1,160 ) (1,628 ) Divestitures — — (47 ) Impairment of properties — — (13 ) Exploratory well costs charged to exploration and abandonment expense (1 ) (17 ) (26 ) Ending capitalized exploratory well costs $ 323 $ 306 $ 305 The following table provides an aging, as of December 31, 2016 , 2015 and 2014 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, 2016 2015 2014 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 318 $ 303 $ 305 More than one year 5 3 — $ 323 $ 306 $ 305 Number of projects with exploratory well costs that have been suspended for a period greater than one year 3 1 — The projects with exploratory well costs that have been suspended for a period greater than one year at December 31, 2016 are in the Eagle Ford Shale area. The Company expects to complete one of the suspended wells during 2017 and the remaining two wells during 2018.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	NOTE G. Long-term Debt and Interest Expense Long-term debt, including the effects of issuance costs and issuance discounts consisted of the following components at December 31, 2016 and 2015 : December 31, 2016 2015 (in millions) Outstanding debt principal balances: 5.875% senior notes due 2016 (a) $ — $ 455 6.65% senior notes due 2017 (b) 485 485 6.875% senior notes due 2018 450 450 7.500% senior notes due 2020 450 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 3,235 3,690 Issuance costs and discounts (22 ) (35 ) Long-term debt 3,213 3,655 Less current portion of long-term debt (a) (b) 485 448 Long-term debt $ 2,728 $ 3,207 ______________________________ (a) The 5.875% senior notes, net of $7 million of unamortized issuance costs and issuance discounts, were classified as current in the accompanying consolidated balance sheet as of December 31, 2015. The notes were paid in full in July 2016. (b) The 6.65% senior notes, net of $173 thousand of unamortized issuance costs and issuance discounts, are classified as current in the accompanying consolidated balance sheets as of December 31, 2016. 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, 2016 , 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, 2016 , 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") matured and were repaid in July 2016. The Company funded the $455 million repayment of the 5.875% Senior Notes with cash on hand. The Company's 6.65% senior notes (the "6.65% Senior Notes"), with an outstanding debt principal balance of $485 million , will mature in March 2017. The Company intends to fund the payments due at maturity of the 6.65% Senior Notes with cash on hand. As such, the 6.65% 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. Principal maturities. Principal maturities of long-term debt at December 31, 2016 , are as follows (in millions): 2017 $ 485 2018 $ 450 2019 $ — 2020 $ 450 2021 $ 500 Thereafter $ 1,350 Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Cash payments for interest $ 196 $ 148 $ 193 Amortization of issuance discounts 9 13 12 Amortization of capitalized loan fees 4 5 5 Net changes in accruals 2 25 (22 ) Interest incurred 211 191 188 Less capitalized interest (4 ) (4 ) (4 ) Total interest expense $ 207 $ 187 $ 184

Incentive Plans

Incentive Plans	12 Months Ended
	Dec. 31, 2016
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 for each of the years ended December 31, 2016 , 2015 and 2014 , 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, 2016 , 2015 and 2014 , the Company recognized compensation expense of $23 million , $31 million and $33 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 Amended and Restated 2006 Long-Term Incentive Plan ("LTIP") and the Employee Stock Purchase Plan ("ESPP"). 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. In May 2016, the stockholders of the Company approved a 3.5 million increase in the number of shares available under the plan. The following table shows the number of shares available for issuance pursuant to awards under the LTIP at December 31, 2016 : Approved and authorized awards 12,600,000 Awards issued under plan (7,509,349 ) Awards available for future grant 5,090,651 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, 2016 : Approved and authorized shares 1,250,000 Shares issued (891,746 ) Shares available for future issuance 358,254 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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Restricted stock-Equity Awards $ 66 $ 70 $ 65 Restricted stock-Liability Awards 24 22 28 Stock options (a) — — 2 Performance unit awards 21 18 13 ESPP 2 2 2 Total $ 113 $ 112 $ 110 Income tax benefit $ 34 $ 34 $ 33 _____________________ (a) Cash proceeds received from stock option exercises during 2016 and 2014 amounted to $1 million and $6 million , respectively. There were no stock option exercises during 2015 . As of December 31, 2016 , there was $107 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $29 million attributable to Liability Awards that are expected to be settled in cash on their vesting dates. 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 2016 , the Company awarded 701,363 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 180,383 shares or units representing Liability Awards). The Company's issued shares, as reflected in the accompanying consolidated balance sheet as of December 31, 2016 , do not include 96,242 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, 2016 : Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 1,081,650 $ 151.50 271,031 Shares granted 520,980 $ 122.72 180,383 Shares forfeited (61,690 ) $ 139.88 (18,290 ) Shares vested (463,713 ) $ 141.49 (142,572 ) Outstanding at end of year 1,077,227 $ 143.39 290,552 The weighted average grant-date fair value of restricted stock equity awards awarded during 2016 , 2015 and 2014 was $122.72 , $153.55 and $184.39 , respectively. The grant-date fair value of restricted stock equity awards that vested during 2016 , 2015 and 2014 was $66 million , $76 million and $51 million , respectively. As of December 31, 2016 and 2015 , accounts payable – due to affiliates in the accompanying consolidated balance sheets includes $22 million and $16 million , respectively, 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 cash paid for Liability Awards that vested during 2016 , 2015 and 2014 was $18 million , $29 million and $38 million , respectively. 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, 2016 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 (39,680 ) $ 31.23 Outstanding at end of year 159,378 $ 89.03 4.29 $ 15 Exercisable at end of year 159,378 $ 89.03 4.29 $ 15 The Company has not granted stock options since February 2012. The intrinsic value of options exercised during 2016 and 2014 was $6 million and $12 million , respectively, based on the difference between the market price at the exercise date and the option exercise price. There were no options exercised during 2015 . Performance unit awards. During 2016 , 2015 and 2014 , 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 2016 , 2015 and 2014 performance unit awards were $203.69 , $222.33 and $232.20 , 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 2016 , 2015 and 2014 : 2016 2015 2014 Risk-free interest rate 0.96% 1.03% 0.62% Range of volatilities 28.3 % - 53.6% 26.1 % - 41.3% 29.0 % - 41.5% The following table summarizes the performance unit activity for the year ended December 31, 2016 : Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 148,547 $ 226.74 Units granted 104,114 $ 203.69 Units forfeited (4,821 ) $ 224.76 Units vested (b) (69,284 ) $ 231.63 Ending performance unit awards 178,556 $ 211.46 _____________________ (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 69,284 units that vested during 2016 , 65,255 units vested according to the scheduled timing of the associated award and 4,029 units, which were originally scheduled to vest in 2017, vested upon retirement of the officer to whom the performance unit awards were granted. On December 31, 2016 , the service period lapsed on 65,996 performance unit awards that earned 1.75 shares for each vested award, representing 115,500 aggregate shares of common stock issued on January 3, 2017. The vested performance units that earned 1.75 shares for each vested award included 65,255 units vested in the current year and 741 units that vested in 2015 upon the retirement of the officer to whom the performance unit awards were granted. The grant-date fair value of performance units that vested during 2016 , 2015 and 2014 was $15 million , $17 million and $8 million , respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Beginning asset retirement obligations $ 285 $ 189 $ 194 Obligations assumed in acquisitions 2 — 6 New wells placed on production 2 4 5 Changes in estimates (a) 17 103 7 Disposition of wells — — (14 ) Obligations settled (27 ) (23 ) (21 ) Accretion of discount on continuing operations 18 12 12 Ending asset retirement obligations $ 297 $ 285 $ 189 _____________________ (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 increases in 2016 and 2015 were 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, 2016 and 2015 , the current portions of the Company's asset retirement obligations were $39 million and $40 million , respectively.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2016
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 $34 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. Environmental. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Environmental 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. Obligations following divestitures. In connection with its divestiture transactions, the Company usually retains certain liabilities and provides 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. 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. The Company's future minimum drilling commitments at December 31, 2016 include only drilling rig obligations that are expected to be paid as follows (in millions): 2017 $ 107 2018 $ 82 2019 $ 10 2020 $ — 2021 $ — Thereafter $ — Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the years ended December 31, 2016 , 2015 and 2014 was $ 59 million , $58 million and $66 million , respectively. The payments for the year ended December 31, 2014 include $ 9 million associated with discontinued operations and are included in the loss from discontinued operations, net of tax, in the accompanying consolidated statements of operations. Future minimum lease commitments under noncancelable operating leases at December 31, 2016 are as follows (in millions): 2017 $ 26 2018 $ 24 2019 $ 23 2020 $ 18 2021 $ 4 Thereafter $ 11 Firm purchase, gathering, processing, transportation and fractionation commitments. The Company from time to time enters into, and as of December 31, 2016 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, 2016 are as follows (in millions): 2017 $ 453 2018 $ 463 2019 $ 469 2020 $ 459 2021 $ 409 Thereafter $ 694 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, 2016
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 oil and gas drilling 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 the year ended December 31, 2014 , 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 year ended December 31, 2014, the Company received nil and $50 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 and 2014 , the Company received $2 million and $3 million of fixed payments and $9 million and $18 million of variable payments, respectively, from EFS Midstream. 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) and $103 million of gathering and treating fees during 2015 and 2014 , 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, 2016
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, 2016 : Year Ended December 31, 2016 2015 2014 Vitol, Inc. (a) 19 % 18 % 9 % Plains Marketing LP 16 % 22 % 29 % Occidental Energy Marketing Inc. 16 % 18 % 16 % Enterprise Products Partners L.P. 12 % 12 % 13 % ______________________ (a) Vitol Inc.'s Permian Basin oil systems were acquired by Sunoco Logistics Partners L.P. ("Sunoco") during the fourth quarter of 2016; the Company's contracts with Vitol Inc. have been transferred to Sunoco. 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, 2016 : Year Ended December 31, 2016 2015 2014 Occidental Energy Marketing Inc. 19 % 18 % — % Plains Marketing LP 19 % 18 % — % Exxon Mobil 16 % 9 % — % BP Energy 13 % — % — % Valero Marketing and Supply Company 12 % 37 % 61 % Lonestar/Oneok 10 % 9 % 16 % 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, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Interest income $ 22 $ 3 $ — Deferred compensation plan income 3 4 3 Equity interest in income of EFS Midstream (a) — 5 13 Other income 7 10 10 Total interest and other income $ 32 $ 22 $ 26 ______________________ (a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream.

Other Expense

Other Expense	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Transportation commitment charges (a) $ 109 $ 53 $ 46 Idle drilling and well service equipment charges (b) 64 92 7 Loss from vertical integration services (c) 54 34 16 Impairment of inventory and other property and equipment (d) 8 86 8 Restructuring charges (e) 4 23 — Other 49 27 29 Total other expense $ 288 $ 315 $ 106 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations and charges to terminate rig contracts that were not required to meet planned drilling activities. (c) 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, 2016 , 2015 and 2014 , these net losses include $147 million , $298 million and $374 million of gross vertical integration revenues, respectively, and $201 million , $332 million and $390 million of total vertical integration costs and expenses, respectively. (d) Primarily represents charges of $8 million , $71 million and $8 million to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2016 , 2015 and 2014 , respectively. See Note D for additional information on the fair value of material and supplies inventory. (e) Represents restructuring costs associated with the Company's restructuring of its operations in South Texas in 2016 and Colorado in 2015. See Note B for additional information on the restructuring charges.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
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 received a tax refund of $66 million (net of tax payments) during 2016 and made current and estimated tax payments of $43 million and $22 million (net of tax refunds) during 2015 and 2014 , 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. As of December 31, 2016 , the Company had unrecognized tax benefits of $112 million resulting from research and experimental expenditures related to horizontal drilling and completion innovations. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. The Company expects to resolve the uncertainties associated with the unrecognized tax benefit by December 2017. There were no unrecognized tax benefits as of December 31, 2015 . 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. 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, 2016 , there are no proposed adjustments 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 2012 Various U.S. states 2012 South Africa 2011 The Company's income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Income tax (provision) benefit from continuing operations $ 403 $ 155 $ (556 ) Income tax benefit from discontinued operations $ — $ 2 $ 60 Changes in equity: Excess tax benefit related to stock-based compensation $ 1 $ 7 $ 19 The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Current: U.S. federal $ 22 $ (22 ) $ (3 ) U.S. state 2 (1 ) (1 ) 24 (23 ) (4 ) Deferred: U.S. federal 375 165 (537 ) U.S. state 4 13 (15 ) 379 178 (552 ) Income tax (provision) benefit from continuing operations $ 403 $ 155 $ (556 ) 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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions, except percentages) Income (loss) from continuing operations attributable to common stockholders before income taxes $ (959 ) $ (421 ) $ 1,597 Federal statutory income tax rate 35 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate 336 147 (559 ) State income tax (provision) benefit (net of federal tax) 3 8 (10 ) State valuation allowance (net of federal tax) (3 ) — — State credit for increasing research activities (net of unrecognized tax benefits and federal tax) 4 — — Federal credit for increasing research activities (net of unrecognized tax benefits) 68 — — Premier Silica benefit — — 21 Other (5 ) — (8 ) Income tax (provision) benefit from continuing operations $ 403 $ 155 $ (556 ) Effective income tax rate, excluding net income attributable to the noncontrolling interests 42 % 37 % 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, 2016 and 2015 : December 31, 2016 2015 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 635 $ 441 Credit carryforwards (b) 107 47 Asset retirement obligations 106 102 Incentive plans 81 75 Net deferred hedge losses 32 — Other 30 55 Total deferred tax assets 991 720 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (2,184 ) (1,997 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (204 ) (227 ) Net deferred hedge gains — (272 ) Total deferred tax liabilities (2,388 ) (2,496 ) Net deferred tax liability $ (1,397 ) $ (1,776 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2016 consist of $1.8 billion of U.S. federal NOLs, which expire between 2032 and 2036, and $150 million of Colorado NOLs, which expire between 2027 and 2036, and are net of a $4 million valuation allowance relating to $92 million of Colorado NOLs that the Company believes will more likely than not expire unutilized. (b) Credit carryforwards as of December 31, 2016 consist of $26 million of U.S. federal minimum tax credits and $76 million of U.S. federal credits and $5 million of Texas credits for increasing research activities. The U.S. federal and state research credits exclude $112 million of unrecognized tax benefits.

Net Income (Loss) Per Share Att

Net Income (Loss) Per Share Attributable To Common Stockholders	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Income (loss) from continuing operations $ (556 ) $ (266 ) $ 1,041 Participating basic earnings (a) — — (10 ) Basic and diluted net income (loss) from continuing operations (556 ) (266 ) 1,031 Basic and diluted net loss from discontinued operations — (7 ) (111 ) Basic and diluted net income (loss) attributable to common stockholders $ (556 ) $ (273 ) $ 920 ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock 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 166 million , 149 million and 144 million for the years ended December 31, 2016 , 2015 and 2014 , respectively.

Summary Of Significant Accoun24

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2016
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 2015 and 2014 financial statement and footnote amounts in order to conform them to the 2016 presentations.
Reclassification, Policy [Policy Text Block]	Certain reclassifications have been made to the 2015 and 2014 financial statement and footnote amounts in order to conform them to the 2016 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, 2016 and 2015 , the Company had accounts receivable – trade, net of allowances for bad debts, of $517 million and $384 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, 2016 and 2015 , 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, 2016 and 2015 : As of December 31, 2016 2015 (in millions) Materials and supplies (a) $ 144 $ 132 Commodities 37 23 $ 181 $ 155 ____________________ (a) As of December 31, 2016 and 2015 , the Company's materials and supplies inventories were net of valuation allowances of $28 million and $78 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 eight gas processing plants and nine treating facilities. The Company is the operator of one of the gas processing plants and all nine of the treating facilities. Seven 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, 2016 , 2015 and 2014 were $41 million , $39 million and $56 million , respectively. Third party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $24 million , $27 million and $24 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 2016 , the Company performed its annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step impairment test. Based on the results of the assessment, the Company determined it was not likely that the Company's goodwill was impaired.
Other Property And Equipment, Net	Other property and equipment, net. Other property and equipment is recorded at cost. As of December 31, 2016 and 2015 , the net carrying value of other property and equipment consisted of the following: As of December 31, 2016 (a) 2015 (a) (in millions) Proved and unproved sand properties (b) $ 484 $ 473 Land and buildings 475 468 Equipment and rigs (c) 206 287 Water infrastructure (d) 221 180 Vehicles 15 21 Furniture and fixtures 22 24 Information technology (e) 84 43 Leasehold improvements 22 27 $ 1,529 $ 1,523 ____________________ (a) At December 31, 2016 and 2015 , other property and equipment was net of accumulated depreciation of $866 million and $711 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 pressure pumping and well services on Company-operated properties. As of December 31, 2016 , 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. (e) Information technology costs include hardware and software costs associated with the Company's existing systems and in-progress system upgrades. The primary purpose of the Company's sand mine, pressure pumping, well services and water infrastructure operations is to accommodate the Company's drilling, completion and production 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 mine, pressure pumping, well services and water infrastructure 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.
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.
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 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 oil ("WTI") 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.
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 fair value of the vested portion 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.
New Accounting Pronouncements	New accounting pronouncements. In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-04, "Simplifying the Test of Goodwill Impairment." ASU 2017-04 simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill (Step 2 of the current goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit's carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard's provisions prospectively. Based on the Company's qualitative assessments of goodwill for impairment during the third quarter and fourth quarter of 2016 and 2015, respectively, the Company does not believe this standard will have a material quantitative effect on the consolidated financial statements; however, this standard will change the policy under which the Company performs its annual impairment assessment by eliminating Step 2 of the test. In June 2016, the FASB issued ASU 2016-13, "Measurement of Credit Losses on Financial Instruments." ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company does not believe this standard will have a material impact on its consolidated financial statements. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Company does not believe this standard will have a material impact on its consolidated financial statements. In February 2016, FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have 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. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified approach to adopt the new standards and the Company plans to utilize the modified approach to adopt the new standard upon its effective date. The Company is evaluating the new guidance, including identification of revenue streams and review of contracts and procedures currently in place. The Company does not anticipate this standard will have a material impact on its consolidated financial statements.

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, 2016
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 Accoun26

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 : As of December 31, 2016 2015 (in millions) Materials and supplies (a) $ 144 $ 132 Commodities 37 23 $ 181 $ 155 ____________________ (a) As of December 31, 2016 and 2015 , the Company's materials and supplies inventories were net of valuation allowances of $28 million and $78 million , respectively. See Note D for additional information regarding inventory impairments.
Other Property Plant and Equipment [Table Text Block]	As of December 31, 2016 and 2015 , the net carrying value of other property and equipment consisted of the following: As of December 31, 2016 (a) 2015 (a) (in millions) Proved and unproved sand properties (b) $ 484 $ 473 Land and buildings 475 468 Equipment and rigs (c) 206 287 Water infrastructure (d) 221 180 Vehicles 15 21 Furniture and fixtures 22 24 Information technology (e) 84 43 Leasehold improvements 22 27 $ 1,529 $ 1,523 ____________________ (a) At December 31, 2016 and 2015 , other property and equipment was net of accumulated depreciation of $866 million and $711 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 pressure pumping and well services on Company-operated properties. As of December 31, 2016 , 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. (e) Information technology costs include hardware and software costs associated with the Company's existing systems and in-progress system upgrades.

Acquisitions and Divestitures A

Acquisitions and Divestitures Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
Business Acquisition [Line Items]
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 and 2014 . The Company did not recognize any income or loss from discontinued operations in 2016. Year Ended December 31, 2015 2014 (in millions) Revenues and other income (a) $ 1 $ 238 Costs and expenses (b) 10 409 Loss from discontinued operations before income taxes (9 ) (171 ) Current tax provision (1 ) — Deferred tax benefit 3 60 Loss from discontinued operations, net of tax $ (7 ) $ (111 ) ____________________ (a) Revenues and other income for the year ended December 31, 2014 was primarily comprised of oil and gas revenues of $198 million . (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 during the year ended December 31, 2014 on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 also included oil and gas production costs of $60 million . 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 28

Disclosures About Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2016 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, 2016 (in millions) Assets: Commodity derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 6 — 6 Deferred compensation plan assets 83 — — 83 Total assets 83 14 — 97 Liabilities: Commodity derivatives — 84 — 84 Total liabilities — 84 — 84 Total recurring fair value measurements $ 83 $ (70 ) $ — $ 13 Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant 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, Nonrecurring [Table Text Block]	The following table presents the fair value and fair value adjustments (in millions) for the Company's 2016 and 2015 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 West Panhandle March 2016 $ 33 $ (32 ) $ 49.77 $ 3.24 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
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 year ended December 31, 2014 related to assets associated with divestitures: Year Ended December 31, 2014 Classification 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 ) Pioneer Alaska Discontinued operations $ 253 $ (97 )
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, 2016 and 2015 are as follows: December 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 1,906 $ 1,901 $ 275 $ 275 Current portion of long-term debt $ 485 $ 490 $ 448 $ 462 Long-term debt $ 2,728 $ 2,956 $ 3,207 $ 3,206
Cash, Cash Equivalents and Investments [Table Text Block]	December 31, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 1,073 $ 45 $ — $ — $ 1,118 Short-term investments — 368 691 382 1,441 Long-term investments — — 420 — 420 $ 1,073 $ 413 $ 1,111 $ 382 $ 2,979

Derivative Financial Instrume29

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and the weighted average oil prices for those contracts: 2017 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Collar contracts: Volume (Bbl) 6,000 6,000 6,000 6,000 — Average price per Bbl: Ceiling $ 70.40 $ 70.40 $ 70.40 $ 70.40 $ — Floor $ 50.00 $ 50.00 $ 50.00 $ 50.00 $ — Collar contracts with short puts (a): Volume (Bbl) 119,000 129,000 147,000 155,000 20,000 Price per Bbl: Ceiling $ 61.36 $ 61.19 $ 62.03 $ 62.12 $ 65.14 Floor $ 48.67 $ 48.46 $ 49.81 $ 49.82 $ 50.00 Short put $ 40.65 $ 40.45 $ 41.07 $ 41.02 $ 40.00 Rollfactor swap contracts (b): Volume (Bbl) 13,111 20,000 20,000 20,000 — NYMEX roll price $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ — Basis swap contracts: Midland-Cushing index swap volume (Bbl) — — — 3,000 740 Price differential ($/Bbl) (c) $ — $ — $ — $ (0.65 ) $ (0.65 ) _______________ (a) During the year ended December 31, 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl. (b) Represents swaps that fix the difference between (i) each day's price per Bbl of WTI for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. (c) Represents the basis differential between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma.
Schedule of NGL Derivative Volumes and Weighted Average Prices [Table Text Block]	2017 First Quarter Second Quarter Third Quarter Fourth Quarter Ethane collar contracts (a): Volume (Bbl) 3,000 3,000 3,000 3,000 Price per Bbl: Ceiling $ 11.83 $ 11.83 $ 11.83 $ 11.83 Floor $ 8.68 $ 8.68 $ 8.68 $ 8.68 Butane collar contracts with short puts (b): Volume (Bbl) — 2,000 2,000 — Price per Bbl: Ceiling $ — $ 36.12 $ 36.12 $ — Floor $ — $ 29.25 $ 29.25 $ — Short put $ — $ 23.40 $ 23.40 $ — ____________________ (a) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. (b) Represent collar contracts with short puts that reduce the price volatility of butane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
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, 2016 and the weighted average gas prices for those contracts: 2017 Year Ending December 31, First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Collar contracts with short puts (a): Volume (MMBtu) 190,000 190,000 190,000 190,000 57,397 Price per MMBtu: Ceiling $ 3.51 $ 3.51 $ 3.51 $ 3.51 $ 3.51 Floor $ 2.93 $ 2.93 $ 2.93 $ 2.93 $ 2.85 Short put $ 2.46 $ 2.46 $ 2.46 $ 2.46 $ 2.33 Basis swap contracts: Mid-Continent index swap volume (b) 45,000 45,000 45,000 45,000 — Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ — Permian Basin index swap volume (c) 40,000 — — — — Price differential ($/MMBtu) $ 0.37 $ — $ — $ — $ — ____________________ (a) Subsequent to December 31, 2016, the Company entered into additional gas collar contracts with short puts for 20,000 MMBtu per day of January 2018 through March 2018 production with a ceiling price of $4.20 per MMBtu, a floor price of $3.55 per MMBtu and a short put price of $2.85 per MMBtu. (b) Represents swaps that fix the basis differentials between the index prices at which the Company sells its Mid-Continent gas and the HH index price used in gas swap and collar contracts with short puts. (c) 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.
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, 2016 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 $ 33 $ (25 ) $ 8 Interest rate derivatives Derivatives - current $ 6 $ — 6 $ 14 Liability Derivatives: Commodity price derivatives Derivatives - current $ 102 $ (25 ) $ 77 Commodity price derivatives Derivatives - noncurrent $ 7 $ — 7 $ 84 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
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, 2016 2015 2014 (in millions) Commodity price derivatives Derivative gains (losses), net $ (174 ) $ 873 $ 697 Interest rate derivatives Derivative gains (losses), net 13 6 15 Total $ (161 ) $ 879 $ 712
Schedule of Derivative Assets and Liabilities by Counterparty [Table Text Block]	The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2016 : Net Assets (Liabilities) (in millions) JP Morgan Chase $ (19 ) Macquarie Bank (11 ) Societe Generale (9 ) BNP Paribas (7 ) Citibank, N.A. (6 ) J. Aron & Company (5 ) Toronto Dominion (5 ) Morgan Stanley (4 ) Nextera Energy (3 ) Merrill Lynch (2 ) Wells Fargo Bank, N.A. (2 ) Scotia Bank 3 Total $ (70 )

Exploratory Well Costs (Tables)

Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Beginning capitalized exploratory well costs $ 306 $ 305 $ 159 Additions to exploratory well costs pending the determination of proved reserves 1,387 1,178 1,860 Reclassification due to determination of proved reserves (1,369 ) (1,160 ) (1,628 ) Divestitures — — (47 ) Impairment of properties — — (13 ) Exploratory well costs charged to exploration and abandonment expense (1 ) (17 ) (26 ) Ending capitalized exploratory well costs $ 323 $ 306 $ 305
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, 2016 , 2015 and 2014 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, 2016 2015 2014 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 318 $ 303 $ 305 More than one year 5 3 — $ 323 $ 306 $ 305 Number of projects with exploratory well costs that have been suspended for a period greater than one year 3 1 —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Components Of Long-Term Debt	Long-term debt, including the effects of issuance costs and issuance discounts consisted of the following components at December 31, 2016 and 2015 : December 31, 2016 2015 (in millions) Outstanding debt principal balances: 5.875% senior notes due 2016 (a) $ — $ 455 6.65% senior notes due 2017 (b) 485 485 6.875% senior notes due 2018 450 450 7.500% senior notes due 2020 450 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 3,235 3,690 Issuance costs and discounts (22 ) (35 ) Long-term debt 3,213 3,655 Less current portion of long-term debt (a) (b) 485 448 Long-term debt $ 2,728 $ 3,207 ______________________________ (a) The 5.875% senior notes, net of $7 million of unamortized issuance costs and issuance discounts, were classified as current in the accompanying consolidated balance sheet as of December 31, 2015. The notes were paid in full in July 2016. (b) The 6.65% senior notes, net of $173 thousand of unamortized issuance costs and issuance discounts, are classified as current in the accompanying consolidated balance sheets as of December 31, 2016.
Principal Maturities Of Long-Term Debt	Principal maturities of long-term debt at December 31, 2016 , are as follows (in millions): 2017 $ 485 2018 $ 450 2019 $ — 2020 $ 450 2021 $ 500 Thereafter $ 1,350
Interest Expense	The following amounts have been incurred and charged to interest expense for the years ended December 31, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Cash payments for interest $ 196 $ 148 $ 193 Amortization of issuance discounts 9 13 12 Amortization of capitalized loan fees 4 5 5 Net changes in accruals 2 25 (22 ) Interest incurred 211 191 188 Less capitalized interest (4 ) (4 ) (4 ) Total interest expense $ 207 $ 187 $ 184

Incentive Plans (Tables)

Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 : Approved and authorized awards 12,600,000 Awards issued under plan (7,509,349 ) Awards available for future grant 5,090,651
Schedule Of Employee Stock Purchase Plan	The following table shows the number of shares available for issuance under the ESPP at December 31, 2016 : Approved and authorized shares 1,250,000 Shares issued (891,746 ) Shares available for future issuance 358,254
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Restricted stock-Equity Awards $ 66 $ 70 $ 65 Restricted stock-Liability Awards 24 22 28 Stock options (a) — — 2 Performance unit awards 21 18 13 ESPP 2 2 2 Total $ 113 $ 112 $ 110 Income tax benefit $ 34 $ 34 $ 33 _____________________ (a) Cash proceeds received from stock option exercises during 2016 and 2014 amounted to $1 million and $6 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, 2016 : Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 1,081,650 $ 151.50 271,031 Shares granted 520,980 $ 122.72 180,383 Shares forfeited (61,690 ) $ 139.88 (18,290 ) Shares vested (463,713 ) $ 141.49 (142,572 ) Outstanding at end of year 1,077,227 $ 143.39 290,552
Schedule Of Stock Options Awards Activity	A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2016 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 (39,680 ) $ 31.23 Outstanding at end of year 159,378 $ 89.03 4.29 $ 15 Exercisable at end of year 159,378 $ 89.03 4.29 $ 15
Schedule of Assumptions Used [Table Text Block]	The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2016 , 2015 and 2014 : 2016 2015 2014 Risk-free interest rate 0.96% 1.03% 0.62% Range of volatilities 28.3 % - 53.6% 26.1 % - 41.3% 29.0 % - 41.5%
Schedule Of Performance Unit Activity	The following table summarizes the performance unit activity for the year ended December 31, 2016 : Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 148,547 $ 226.74 Units granted 104,114 $ 203.69 Units forfeited (4,821 ) $ 224.76 Units vested (b) (69,284 ) $ 231.63 Ending performance unit awards 178,556 $ 211.46 _____________________ (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 69,284 units that vested during 2016 , 65,255 units vested according to the scheduled timing of the associated award and 4,029 units, which were originally scheduled to vest in 2017, vested upon retirement of the officer to whom the performance unit awards were granted. On December 31, 2016 , the service period lapsed on 65,996 performance unit awards that earned 1.75 shares for each vested award, representing 115,500 aggregate shares of common stock issued on January 3, 2017. The vested performance units that earned 1.75 shares for each vested award included 65,255 units vested in the current year and 741 units that vested in 2015 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, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Beginning asset retirement obligations $ 285 $ 189 $ 194 Obligations assumed in acquisitions 2 — 6 New wells placed on production 2 4 5 Changes in estimates (a) 17 103 7 Disposition of wells — — (14 ) Obligations settled (27 ) (23 ) (21 ) Accretion of discount on continuing operations 18 12 12 Ending asset retirement obligations $ 297 $ 285 $ 189 _____________________ (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 increases in 2016 and 2015 were 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, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Drilling Commitments [Table Text Block]	future minimum drilling commitments at December 31, 2016 include only drilling rig obligations that are expected to be paid as follows (in millions): 2017 $ 107 2018 $ 82 2019 $ 10 2020 $ — 2021 $ — Thereafter $ —
Future Minimum Lease Commitments	Future minimum lease commitments under noncancelable operating leases at December 31, 2016 are as follows (in millions): 2017 $ 26 2018 $ 24 2019 $ 23 2020 $ 18 2021 $ 4 Thereafter $ 11
Future Minimum Gathering, Processing And Transportation Fees	Future minimum purchase, gathering, processing, transportation and fractionation commitments at December 31, 2016 are as follows (in millions): 2017 $ 453 2018 $ 463 2019 $ 469 2020 $ 459 2021 $ 409 Thereafter $ 694

Major Customers (Tables)

Major Customers (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 : Year Ended December 31, 2016 2015 2014 Vitol, Inc. (a) 19 % 18 % 9 % Plains Marketing LP 16 % 22 % 29 % Occidental Energy Marketing Inc. 16 % 18 % 16 % Enterprise Products Partners L.P. 12 % 12 % 13 % ______________________ (a) Vitol Inc.'s Permian Basin oil systems were acquired by Sunoco Logistics Partners L.P. ("Sunoco") during the fourth quarter of 2016; the Company's contracts with Vitol Inc. have been transferred to Sunoco.
Schedule of Sales of Purchased Oil and Gas by Major Customer	Year Ended December 31, 2016 2015 2014 Occidental Energy Marketing Inc. 19 % 18 % — % Plains Marketing LP 19 % 18 % — % Exxon Mobil 16 % 9 % — % BP Energy 13 % — % — % Valero Marketing and Supply Company 12 % 37 % 61 % Lonestar/Oneok 10 % 9 % 16 %

Interest And Other Income (Tabl

Interest And Other Income (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Interest income $ 22 $ 3 $ — Deferred compensation plan income 3 4 3 Equity interest in income of EFS Midstream (a) — 5 13 Other income 7 10 10 Total interest and other income $ 32 $ 22 $ 26 ______________________ (a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. 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, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Transportation commitment charges (a) $ 109 $ 53 $ 46 Idle drilling and well service equipment charges (b) 64 92 7 Loss from vertical integration services (c) 54 34 16 Impairment of inventory and other property and equipment (d) 8 86 8 Restructuring charges (e) 4 23 — Other 49 27 29 Total other expense $ 288 $ 315 $ 106 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations and charges to terminate rig contracts that were not required to meet planned drilling activities. (c) 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, 2016 , 2015 and 2014 , these net losses include $147 million , $298 million and $374 million of gross vertical integration revenues, respectively, and $201 million , $332 million and $390 million of total vertical integration costs and expenses, respectively. (d) Primarily represents charges of $8 million , $71 million and $8 million to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2016 , 2015 and 2014 , respectively. See Note D for additional information on the fair value of material and supplies inventory. (e) Represents restructuring costs associated with the Company's restructuring of its operations in South Texas in 2016 and Colorado in 2015. See Note B for additional information on the restructuring charges.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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 2012 Various U.S. states 2012 South Africa 2011
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Income tax (provision) benefit from continuing operations $ 403 $ 155 $ (556 ) Income tax benefit from discontinued operations $ — $ 2 $ 60 Changes in equity: Excess tax benefit related to stock-based compensation $ 1 $ 7 $ 19
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Current: U.S. federal $ 22 $ (22 ) $ (3 ) U.S. state 2 (1 ) (1 ) 24 (23 ) (4 ) Deferred: U.S. federal 375 165 (537 ) U.S. state 4 13 (15 ) 379 178 (552 ) Income tax (provision) benefit from continuing operations $ 403 $ 155 $ (556 )
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions, except percentages) Income (loss) from continuing operations attributable to common stockholders before income taxes $ (959 ) $ (421 ) $ 1,597 Federal statutory income tax rate 35 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate 336 147 (559 ) State income tax (provision) benefit (net of federal tax) 3 8 (10 ) State valuation allowance (net of federal tax) (3 ) — — State credit for increasing research activities (net of unrecognized tax benefits and federal tax) 4 — — Federal credit for increasing research activities (net of unrecognized tax benefits) 68 — — Premier Silica benefit — — 21 Other (5 ) — (8 ) Income tax (provision) benefit from continuing operations $ 403 $ 155 $ (556 ) Effective income tax rate, excluding net income attributable to the noncontrolling interests 42 % 37 % 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, 2016 and 2015 : December 31, 2016 2015 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 635 $ 441 Credit carryforwards (b) 107 47 Asset retirement obligations 106 102 Incentive plans 81 75 Net deferred hedge losses 32 — Other 30 55 Total deferred tax assets 991 720 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (2,184 ) (1,997 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (204 ) (227 ) Net deferred hedge gains — (272 ) Total deferred tax liabilities (2,388 ) (2,496 ) Net deferred tax liability $ (1,397 ) $ (1,776 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2016 consist of $1.8 billion of U.S. federal NOLs, which expire between 2032 and 2036, and $150 million of Colorado NOLs, which expire between 2027 and 2036, and are net of a $4 million valuation allowance relating to $92 million of Colorado NOLs that the Company believes will more likely than not expire unutilized. (b) Credit carryforwards as of December 31, 2016 consist of $26 million of U.S. federal minimum tax credits and $76 million of U.S. federal credits and $5 million of Texas credits for increasing research activities. The U.S. federal and state research credits exclude $112 million of unrecognized tax benefits.

Net Income (Loss) Per Share A39

Net Income (Loss) Per Share Attributable To Common Stockholders (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 : Year Ended December 31, 2016 2015 2014 (in millions) Income (loss) from continuing operations $ (556 ) $ (266 ) $ 1,041 Participating basic earnings (a) — — (10 ) Basic and diluted net income (loss) from continuing operations (556 ) (266 ) 1,031 Basic and diluted net loss from discontinued operations — (7 ) (111 ) Basic and diluted net income (loss) attributable to common stockholders $ (556 ) $ (273 ) $ 920 ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so.

Summary Of Significant Accoun40

Summary Of Significant Accounting Policies (Narrative) (Details) shares in Thousands, $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)shares	Mar. 31, 2016USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)shares
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable - trade			$ 517	$ 384
Allowances for doubtful accounts			$ 1	1
Natural gas processing plants number			8
Treating facilities number			9
Company operated natural gas processing plants			1
Company Operated Treating Facilities			9
Third party operated natural gas processing plants			7
Nonoperated treating facilities			6
Third party revenues, processing plants and treating facilities			$ 41	39	$ 56
Third party expenses, processing plants and treating facilities			$ 24	27	$ 24
Stock Issued During Period, Shares, New Issues | shares	6,000	13,800	19,840		5,750
Proceeds from Issuance of Common Stock	$ 937	$ 1,600	$ 2,534	0	$ 980
Unrecognized Tax Benefits			112
Restructuring and Related Cost, Incurred Cost			4	23	$ 0
Restructuring Reserve			2	4
Employee Severance [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost				17
Employee Relocation [Member]
Summary Of Significant Accounting Policies [Line Items]
Restructuring and Related Cost, Incurred Cost			1
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			$ 3	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

Summary Of Significant Accoun41

Summary Of Significant Accounting Policies (Schedule of Inventory) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Schedule of Inventory [Line Items]
Materials and supplies inventories	[1]	$ 144	$ 132
Commodities		37	23
Inventories		181	155
Net materials and supplies inventories reserves		$ 28	$ 78
[1]	As of December 31, 2016 and 2015, the Company's materials and supplies inventories were net of valuation allowances of $28 million and $78 million, respectively. See Note D for additional information regarding inventory impairments.

Summary of Significant Accoun42

Summary of Significant Accounting Policies (Schedule of Other Property Plant and Equipment) (Details) $ in Millions		Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net	[1]	$ 1,529	$ 1,523
Accumulated depreciation property, plant and equipment, other assets		$ 866	711
Fracture Stimulation Fleets		8
Proved and Unproved Sand Leaseholds [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net	[2]	$ 484	473
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		475	468
Wells and Related Equipment and Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		206	287
Water infrastructure [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		221	180
Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		15	21
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		22	24
Computer Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		84	43
Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net		$ 22	$ 27
[1]	At December 31, 2016 and 2015, other property and equipment was net of accumulated depreciation of $866 million and $711 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 Divestitures43

Acquisitions and Divestitures Acquisition and Divestitures (Business Combination) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)aBoe	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Business acquisition	$ 428	$ 0	$ 0
Permian Basin [Member]
Business Acquisition [Line Items]
Gas and Oil Area, Developed, Net | a	28,000
Production, Barrels of Oil Equivalents | Boe	1,400
Business acquisition	$ 428
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	79
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	347
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Buildings	5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other	(2)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	(1)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	428
Business Acquisition, Transaction Costs	$ 1

Acquisitions and Divestitures (

Acquisitions and Divestitures (Discontinued Operations Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)Rate	Dec. 31, 2014USD ($)
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net	$ 2	$ 782	$ 9
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	64	92	7
Proceeds from disposition of assets, net of cash sold	507	553	877
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	28	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
Other Assets [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Gain on disposition of assets, net	$ 2	5	$ 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]
Proceeds from disposition of assets, net of cash sold			$ 150
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
Proceeds Received Prior Year [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Equity Method Investment, Net Sales Proceeds		530
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		$ 501

Acquisitions and Divestitures45

Acquisitions and Divestitures (Components of Discontinued Operations) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and Gas Revenue		$ 2,418	$ 2,178	$ 3,599
Oil and Gas Production Expense		581	717	693
Impairment of oil and gas properties		32	1,056	0
Costs and expenses, Total		4,783	5,246	3,475
Current		24	(23)	(4)
Deferred		379	178	(552)
Loss from discontinued operations		$ 0	(7)	(111)
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and Gas Revenue				198
Total revenues and other income from discontinued operations			1	238
Oil and Gas Production Expense				60
Impairment of oil and gas properties	[1]			305
Costs and expenses, Total			10	409
Income (loss) from discontinued operations before income taxes			(9)	(171)
Current			(1)	0
Deferred			3	60
Loss from discontinued operations			$ (7)	$ (111)
[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 during the year ended December 31, 2014 on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 also included oil and gas production costs of $60 million. 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory Write-down	$ 8	$ 71	$ 8
discount rate used in impairment calculation	10.00%
Pioneer Alaska [Member]
Impairment of Long-Lived Assets Held-for-use	$ 32
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 Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	$ 83,000	$ 73,000
Assets, Fair Value Disclosure	97,000	831,000
Liabilities, Fair Value Disclosure	84,000	1,000
Recurring Measurements, (Fair Value, Total)	13,000	830,000
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	8,000	758,000
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	84,000	1,000
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	6,000
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	83,000	73,000
Assets, Fair Value Disclosure	83,000	73,000
Liabilities, Fair Value Disclosure	0	0
Recurring Measurements, (Fair Value, Total)	83,000	73,000
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 Asset, Fair Value, Amount Not Offset Against Collateral	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	14,000	758,000
Liabilities, Fair Value Disclosure	84,000	1,000
Recurring Measurements, (Fair Value, Total)	(70,000)	757,000
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	8,000	758,000
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	84,000	1,000
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 Asset, Fair Value, Amount Not Offset Against Collateral	6,000
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 Asset, Fair Value, Amount Not Offset Against Collateral	$ 0

Disclosures About Fair Value 48

Disclosures About Fair Value Measurements (Measured On A Nonrecurring Basis) (Details) $ in Millions	3 Months Ended				12 Months Ended
	Mar. 31, 2016USD ($)$ / MMBTU$ / bbl	Dec. 31, 2015USD ($)$ / MMBTU$ / bbl	Sep. 30, 2015USD ($)$ / MMBTU$ / bbl	Mar. 31, 2015USD ($)$ / MMBTU$ / bbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties					$ (32)	$ (1,056)	$ 0
Management oil price outlook | $ / bbl	49.77	52.82	57.41	65.02
Management gas price outlook | $ / MMBTU	3.24	3.34	3.46	3.83
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				$ 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	$ 33			$ 61
Impairment of oil and gas properties	$ 32			$ 138

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties		$ (32)	$ (1,056)	$ 0
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
Pioneer Alaska [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group				253
Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties	[1]			(305)
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
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
[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 during the year ended December 31, 2014 on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 also included oil and gas production costs of $60 million. 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, 2016	Dec. 31, 2015
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Long-term Debt, Current Maturities	$ 485	$ 448
Long-term Debt, Excluding Current Maturities	2,728	3,207
Reported Value Measurement [Member]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Investments	1,906	275
Long-term Debt, Current Maturities	485	448
Long-term Debt, Excluding Current Maturities	2,728	3,207
Estimate of Fair Value Measurement [Member]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Investments	1,901	275
Long-term Debt, Current Maturities	490	462
Long-term Debt, Excluding Current Maturities	$ 2,956	$ 3,206

Disclosures About Fair Value 51

Disclosures About Fair Value Measurements Schedule of Fair Value Measurements (Cash and Cash Equivalents and Investments) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents	$ 1,118	$ 1,391	$ 1,025	$ 393
Short-term Investments	1,441	0
Long-term Investments	420	$ 0
Cash, Cash Equivalents, and Short-term Investments	2,979
Cash and Cash Equivalents [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents	1,073
Short-term Investments	0
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	1,073
Commercial Paper [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents	45
Short-term Investments	368
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	413
Corporate Bond Securities [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents	0
Short-term Investments	691
Long-term Investments	420
Cash, Cash Equivalents, and Short-term Investments	1,111
Bank Time Deposits [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents	0
Short-term Investments	382
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	$ 382

Derivative Financial Instrume52

Derivative Financial Instruments (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MMBTU / dRate
Schedule of Trading Securities and Other Trading Assets [Line Items]
Notional amount of debt	$ 100
Derivative fixed interest rate | Rate	1.81%
Diesel Swap Year 2 [Member] | Swap Contracts for Year 2 [Member]
Schedule of Trading Securities and Other Trading Assets [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	1,000
Proceeds from Termination of Diesel Derivatives	$ 2
Interest Rate Derivatives [Member]
Schedule of Trading Securities and Other Trading Assets [Line Items]
Notional amount of debt	150
Proceeds from Termination of Interest Rate Derivatives	$ 7

Derivative Financial Instrume53

Derivative Financial Instruments (Oil Derivative Contracts Volume And Weighted Average Price) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)bbl / d$ / bbl
Oil contracts, price per bbl [Member] | Collar Contract For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	70.40
Derivative, Average Floor Price	50
Oil contracts, price per bbl [Member] | Collar Contract For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	70.40
Derivative, Average Floor Price	50
Oil contracts, price per bbl [Member] | Collar Contract For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	70.40
Derivative, Average Floor Price	50
Oil contracts, price per bbl [Member] | Collar Contract For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	70.40
Derivative, Average Floor Price	50
Oil contracts, price per bbl [Member] | Collar Contracts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	0
Derivative, Average Floor 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	61.36
Derivative, Average Floor Price	48.67
Derivative, Notional Amount, Price Per Unit	40.65
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	61.19
Derivative, Average Floor Price	48.46
Derivative, Notional Amount, Price Per Unit	40.45
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	62.03
Derivative, Average Floor Price	49.81
Derivative, Notional Amount, Price Per Unit	41.07
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	62.12
Derivative, Average Floor Price	49.82
Derivative, Notional Amount, Price Per Unit	41.02
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	65.14
Derivative, Average Floor Price	50
Derivative, Notional Amount, Price Per Unit	40
Oil contracts, price per bbl [Member] | Rollfactor Swap Contracts For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.32)
Oil contracts, price per bbl [Member] | Rollfactor Swap Contracts For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.32)
Oil contracts, price per bbl [Member] | Rollfactor Swap Contracts For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.32)
Oil contracts, price per bbl [Member] | Rollfactor Swap Contracts For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.32)
Oil contracts, price per bbl [Member] | Rollfactor Swap Contracts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	0	[1]
Oil contracts, price per bbl [Member] | Basis Swap Contracts for First 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] | Collar Contracts With Short Puts for Year 2 - Converted [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	60.76
Derivative, Average Floor Price	45
Derivative, Notional Amount, Price Per Unit	40
Oil contracts, price per bbl [Member] | Basis Swap Contracts for Second 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] | Basis 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] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.65)
Oil contracts, price per bbl [Member] | Basis Swap Contracts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.65)
Oil contracts [Member] | Collar Contract For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
Oil contracts [Member] | Collar Contract For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
Oil contracts [Member] | Collar Contract For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
Oil contracts [Member] | Collar Contract For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
Oil contracts [Member] | Collar 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	119,000
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	129,000
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	147,000
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	155,000
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	20,000	[2],[3]
Oil contracts [Member] | Rollfactor Swap Contracts For First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	13,111
Oil contracts [Member] | Rollfactor Swap Contracts For Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	20,000
Oil contracts [Member] | Rollfactor Swap Contracts For Third Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	20,000
Oil contracts [Member] | Rollfactor Swap Contracts For Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	20,000
Oil contracts [Member] | Rollfactor Swap Contracts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	0
Oil contracts [Member] | Basis Swap Contracts for First Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	0
Premium Paid on Derivative Contract | $	$ 24
Oil contracts [Member] | Collar Contracts With Short Puts for Year 2 - Converted [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	33,000
Oil contracts [Member] | Basis Swap Contracts for Second Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	0
Oil contracts [Member] | Basis 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] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	3,000
Oil contracts [Member] | Basis Swap Contracts for Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	740
[1]	Represents the basis differential between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma.
[2]	During the year ended December 31, 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl.
[3]	Represents swaps that fix the difference between (i) each day's price per Bbl of WTI for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333.

Derivative Financial Instrume54

Derivative Financial Instruments Derivative Financial Instruments (NGL Derivative Contracts Volume and Weighted Average Price) (Details)	Feb. 17, 2017bbl / dMMBTU / d$ / bbl	Dec. 31, 2016bbl / d$ / bbl
NGL contract, in BBLS [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		0
NGL contract, in BBLS [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		2,000
NGL contract, in BBLS [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		2,000
NGL contract, in BBLS [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		0
NGL contract, in BBLS [Member] | Collar Contract For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		3,000
NGL contract, in BBLS [Member] | Collar Contract For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		3,000
NGL contract, in BBLS [Member] | Collar Contract For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		3,000
NGL contract, in BBLS [Member] | Collar Contract For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		3,000
NGL contracts, price per BBL [Member] | Collar Contracts With Short Puts For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		0
Derivative, Average Floor Price		0
Derivative, Notional Amount, Price Per Unit		0
NGL contracts, price per BBL [Member] | Collar Contracts With Short Puts For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		36.12
Derivative, Average Floor Price		29.25
Derivative, Notional Amount, Price Per Unit		23.40
NGL contracts, price per BBL [Member] | Collar Contracts With Short Puts For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		36.12
Derivative, Average Floor Price		29.25
Derivative, Notional Amount, Price Per Unit		23.40
NGL contracts, price per BBL [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		0
Derivative, Average Floor Price		0
Derivative, Notional Amount, Price Per Unit		0
NGL contracts, price per BBL [Member] | Collar Contract For First Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		11.83
Derivative, Average Floor Price		8.68
NGL contracts, price per BBL [Member] | Collar Contract For Second Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		11.83
Derivative, Average Floor Price		8.68
NGL contracts, price per BBL [Member] | Collar Contract For Third Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		11.83
Derivative, Average Floor Price		8.68
NGL contracts, price per BBL [Member] | Collar Contract For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		11.83
Derivative, Average Floor Price		8.68
Subsequent Event [Member] | NGL contract, in BBLS [Member] | Swap Contracts For April to September of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	2,000
Derivative, Swap Type, Average Fixed Price	34.86
Subsequent Event [Member] | NGL contract, in BBLS [Member] | Swap Contracts For March Current Year to December Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	2,500
Derivative, Swap Type, Average Fixed Price	1.60
Subsequent Event [Member] | NGL contract, MMBtu Equivalent [Member] | Swap Contracts For March Current Year to December Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	6,920

Derivative Financial Instrume55

Derivative Financial Instruments (Gas Derivative Contracts Volume And Weighted Average Price) (Details)		Feb. 17, 2017MMBTU / d$ / MMBTU	Dec. 31, 2016MMBTU / d$ / MMBTU
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			190,000
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			190,000
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			190,000
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			190,000
Gas contracts, in MMBTU [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			57,397
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			3.51
Derivative, Average Floor Price			2.93
Derivative, Notional Amount, Price Per Unit			2.46
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			3.51
Derivative, Average Floor Price			2.93
Derivative, Notional Amount, Price Per Unit			2.46
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			3.51
Derivative, Average Floor Price			2.93
Derivative, Notional Amount, Price Per Unit			2.46
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			3.51
Derivative, Average Floor Price			2.93
Derivative, Notional Amount, Price Per Unit			2.46
Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price			3.51
Derivative, Average Floor Price			2.85
Derivative, Notional Amount, Price Per Unit			2.33
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			45,000
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			45,000
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			45,000
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			45,000
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]		0
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
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			40,000
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			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			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			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			0.37
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] | Gas contracts, in MMBTU [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d		20,000
Subsequent Event [Member] | Gas contracts, price per MMBTU [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price		4.20
Derivative, Average Floor Price		3.55
Derivative, Notional Amount, Price Per Unit		2.85
[1]	Subsequent to December 31, 2016, the Company entered into additional gas collar contracts with short puts for 20,000 MMBtu per day of January 2018 through March 2018 production with a ceiling price of $4.20 per MMBtu, a floor price of $3.55 per MMBtu and a short put price of $2.85 per MMBtu.

Derivative Financial Instrume56

Derivative Financial Instruments (Offsetting Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Current	$ 14,000	$ 694,000
Derivative Asset, Noncurrent	0	64,000
Derivative Liability, Current	77,000	0
Derivative Liability, Noncurrent	7,000	1,000
Not Designated As Hedging Instruments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	14,000	758,000
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	84,000	1,000
Derivative Current [Member] | Not Designated As Hedging Instruments [Member] | Commodity Price Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset	33,000	695,000
Total derivatives, Liability	102,000	1,000
Derivative Assets Offset In Balance Sheet	(25,000)	(1,000)
Derivative Liabilities Offset In Balance Sheet	25,000	1,000
Derivative Asset, Current	8,000	694,000
Derivative Liability, Current	77,000	0
Derivative Current [Member] | Not Designated As Hedging Instruments [Member] | Interest Rate Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset	6,000
Derivative Assets Offset In Balance Sheet	0
Derivative Asset, Current	6,000
Derivative Noncurrent [Member] | Not Designated As Hedging Instruments [Member] | Commodity Price Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset		64,000
Total derivatives, Liability	7,000	1,000
Derivative Assets Offset In Balance Sheet		0
Derivative Liabilities Offset In Balance Sheet	0	0
Derivative Asset, Noncurrent		64,000
Derivative Liability, Noncurrent	$ 7,000	$ 1,000

Derivative Financial Instrume57

Derivative Financial Instruments (Derivative Obligations Under Terminated Hedge Arrangements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative gains, net	$ (161)	$ 879	$ 712
Commodity Price Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	(174)	873	697
Interest Rate Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	$ 13	$ 6	$ 15

Schedule of Derivative Assets a

Schedule of Derivative Assets and Liabilities by Counterparty (Details) $ in Millions	Dec. 31, 2016USD ($)
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (70)
JP Morgan Chase [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(19)
Macquarie Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(11)
Societe Generale [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(9)
BNP Paribas [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(7)
Citibank, N.A. [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(6)
J. Aron & Company [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Toronto Dominion [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Morgan Stanley [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(4)
Nextera [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(3)
Merrill Lynch [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(2)
Wells Fargo Bank, N.A. [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(2)
Scotia Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 3

Exploratory Well Costs (Capital

Exploratory Well Costs (Capitalized Exploratory Well And Project Activity) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized Exploratory Well Costs, Beginning Balance		$ 306	$ 305	$ 159
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves		1,387	1,178	1,860
Reclassification due to determination of proved reserves		(1,369)	(1,160)	(1,628)
Capitalized Exploratory Well Cost Assets Disposition		0	0	(47)
Impairment of oil and gas properties		32	1,056	0
Exploratory well costs charged to exploration expense		(1)	(17)	(26)
Capitalized Exploratory Well Costs, Ending Balance		323	306	305
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	[1]			305
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	$ 0	$ (13)
[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 during the year ended December 31, 2014 on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 also included oil and gas production costs of $60 million. 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 (Capit60

Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Capitalized Exploratory Well Costs [Abstract]
One year or less	$ 318	$ 303	$ 305
More than one year	5	3	0
Capitalized exploratory well costs, total suspended	$ 323	$ 306	$ 305	$ 159
Number of projects with exploratory well costs that have been suspended for a period greater than one year	3	1	0

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Line of credit facility, maximum borrowing capacity	$ 1,500
Outstanding borrowings under the Credit Facility	0
Debt instrument, Unamortized Discount and Fee Amounts	22	$ 35
Borrowings under long-term debt	0	998	$ 523
Repayments of Long-term Debt	$ 455	0	$ 523
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%
3.45% Senior Notes Due 2021 [Member]
Issuance of senior notes	$ 500	500
Senior Notes, interest rate, percentage	3.45%
4.45% Senior Notes Due 2022 [Member]
Issuance of senior notes	$ 500	500
Senior Notes, interest rate, percentage	4.45%
Combined 3.45% and 4.45% Senior Notes [Member]
Debt instrument, Unamortized Discount and Fee Amounts		9
Borrowings under long-term debt		991
5.875% Senior Notes Due 2016 [Member]
Issuance of senior notes	$ 0	455
Senior Notes, interest rate, percentage	5.875%
Debt instrument, Unamortized Discount and Fee Amounts		7
6.65% Senior Notes Due 2017 [Member]
Issuance of senior notes	$ 485	$ 485
Senior Notes, interest rate, percentage	6.65%
Debt instrument, Unamortized Discount and Fee Amounts	$ 0
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, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Outstanding debt principal balances, gross	$ 3,235	$ 3,690
Issuance discounts and premiums, net	(22)	(35)
Long-term Debt	3,213	3,655
Outstanding borrowing	0
Long-term Debt, Current Maturities	485	448
Long-term Debt, Excluding Current Maturities	2,728	3,207
5.875% Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Issuance of senior notes	$ 0	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
Issuance discounts and premiums, net	$ 0
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	500
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	500
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, 2016USD ($)
Debt Instrument [Line Items]
2,016	$ 485
2,017	450
2,018	0
2,019	450
2,020	500
Thereafter	$ 1,350

Long-Term Debt (Interest Expens

Long-Term Debt (Interest Expenses) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash payments for interest	$ 196	$ 148	$ 193
Accretion/amortization of discounts or premiums on loans	9	13	12
Amortization of capitalized loan fees	4	5	5
Net changes in accruals	2	25	(22)
Interest incurred	211	191	188
Less capitalized interest	(4)	(4)	(4)
Interest	$ 207	$ 187	$ 184

Incentive Plans (Narrative) (De

Incentive Plans (Narrative) (Details) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2016USD ($)$ / sharesRateshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / 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		$ 113	$ 112	$ 110
Unrecognized share-based compensation expense		$ 107
Restricted Units Vesting Schedule		3 years
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		358,254
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		$ 24	$ 22	28
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares		290,552	271,031
Unrecognized share-based compensation expense		$ 29
Number of Shares granted | shares		180,383
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 18	$ 29	38
Amount of liabilities attributable to liability awards included in accounts payable		$ 22	16
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares granted | shares		701,363
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 66	$ 70	$ 65
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares		1,077,227	1,081,650
Number of Shares granted | shares		520,980
Number of unvested shares | shares		96,242
Weighted Average Grant-Date Fair Value, Shares granted | $ / shares		$ 122.72	$ 153.55	$ 184.39
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 66	$ 76	$ 51
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	[1]	$ 0	$ 0	2
Option awards contract life		10
Average dividend yield		7
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercised, Intrinsic Value		$ 6		$ 12
Performance Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Grant-Date Fair Value, Shares granted | $ / shares		$ 203.69	$ 222.33	$ 232.20
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 15	$ 17	$ 8
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		5,090,651
Approved and authorized awards | shares		12,600,000
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		$ 23	$ 31	$ 33
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 2016 and 2014 amounted to $1 million and $6 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]	128 Months Ended
	Dec. 31, 2016shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	12,600,000
Shares issued	(7,509,349)
Awards available for future grant	5,090,651

Incentive Plans (Schedule Of Em

Incentive Plans (Schedule Of Employee Stock Purchase Plan) (Details) - Employee Stock [Member]	240 Months Ended
	Dec. 31, 2016shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized shares	1,250,000
Shares issued	(891,746)
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	358,254

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 113	$ 112	$ 110
Income Tax (Expense) Benefit		403	155	(556)
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Including Stock Options		1		6
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		66	70	65
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		24	22	28
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	[1]	0	0	2
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		21	18	13
Employee Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense		2	2	2
Compensation Expense For Incentive Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income Tax (Expense) Benefit		$ 34	$ 34	$ 33
[1]	(a)Cash proceeds received from stock option exercises during 2016 and 2014 amounted to $1 million and $6 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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	1,081,650
Number of Shares granted	520,980
Forfeitures, number of shares	(61,690)
Awards vested	(463,713)
Number of Shares/Units, Outstanding at end of year	1,077,227	1,081,650
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year	$ 151.50
Weighted Average Grant-Date Fair Value, Shares granted	122.72	$ 153.55	$ 184.39
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	139.88
Weighted Average Grant-Date Fair Value, Shares vested	141.49
Weighted Average Grant-Date Fair Value, Outstanding at end of year	$ 143.39	$ 151.50
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	271,031
Number of Shares granted	180,383
Forfeitures, number of shares	(18,290)
Awards vested	(142,572)
Number of Shares/Units, Outstanding at end of year	290,552	271,031

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options exercised	(98,000)	(58,000)	(130,000)
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	(39,680)
Number of Shares, Outstanding and expected to vest at end of year	159,378	199,058
Number of Shares, Exercisable at end of year	159,378
Weighted Average Exercise Price, Outstanding at beginning of year	$ 77.51
Weighted Average Exercise Price, Options exercised	31.23
Weighted Average Exercise Price, Outstanding and expected to vest at end of year	89.03	$ 77.51
Weighted Average Exercise Price, Exercisable at end of year	$ 89.03
Weighted Average Remaining Contractual Life, Outstanding and expected to vest at end of year	4 years 3 months 15 days
Weighted Average Remaining Contractual Life, Exercisable at end of year	4 years 3 months 15 days
Aggregate Intrinsic Value, Outstanding and expected to vest at end of year	$ 15
Aggregate Intrinsic Value, Exercisable at end of year	$ 15

Incentive Plans (Schedule Of As

Incentive Plans (Schedule Of Assumptions To Estimate The Fair Value) (Details) - Performance Units [Member]	12 Months Ended
	Dec. 31, 2016Rate	Dec. 31, 2015Rate	Dec. 31, 2014Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.96%	1.03%	0.62%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	53.60%	41.30%	41.50%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	28.30%	26.10%	29.00%

Incentive Plans (Schedule Of Pe

Incentive Plans (Schedule Of Performance Unit Activity) (Details) - $ / shares		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares issued		173,221,845	152,775,920
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year	[1]	148,547
Number of Units granted	[1]	104,114
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	[1]	(4,821)
Awards vested	[1],[2]	(65,255)
Number of Shares/Units, Outstanding at end of year	[1]	178,556	148,547
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year		$ 226.74
Weighted Average Grant-Date Fair Value, Units granted		203.69
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		224.76
Weighted Average Grant Date Fair Value, Units vested	[2]	231.63
Weighted Average Grant-Date Fair Value, Outstanding at end of year		$ 211.46	$ 226.74
Performance percentage of actual payout minimum		0.00%
Performance percentage to reach maximum		250.00%
Number of shares earned for each vested award		1.8
Common stock, shares issued		115,500
Performance Units, including Retirement Deferred Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested	[1],[2]	(69,284)
Retirement Deferred Performance Units [Member] [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested	[1],[2]	(4,029)
Performance Units Service Period Lapsed [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested		(65,996)
Retirement Deferred Performance Units Service Period Lapse [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested		(741)
[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 69,284 units that vested during 2016, 65,255 units vested according to the scheduled timing of the associated award and 4,029 units, which were originally scheduled to vest in 2017, vested upon retirement of the officer to whom the performance unit awards were granted. On December 31, 2016, the service period lapsed on 65,996 performance unit awards that earned 1.75 shares for each vested award, representing 115,500 aggregate shares of common stock issued on January 3, 2017. The vested performance units that earned 1.75 shares for each vested award included 65,255 units vested in the current year and 741 units that vested in 2015 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance		$ 285	$ 189	$ 194
AssetRetirementObligationLiabilitiesAcquiredInBusinessCombination		2	0	6
Liabilities incurred		2	4	5
Changes in estimates	[1]	17	103	7
Disposition of wells		0	0	(14)
Liabilities settled		(27)	(23)	(21)
Accretion of discount on continuing operations		18	12	12
Asset Retirement Obligations, Ending Balance		297	285	$ 189
Asset retirement obligations, current portion		$ 39	$ 40
[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 increases in 2016 and 2015 were 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 Contingencies74

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Commitments and Contingencies Disclosure [Abstract]
Current annual salaries of officers and key employees	$ 34

Commitments And Contingencies C

Commitments And Contingencies Commitments and Contingencies (Future Minimum Drilling Commitments) (Details) $ in Millions	Dec. 31, 2016USD ($)
Commitments and Contingencies Disclosure [Abstract]
Other Commitment, Due in Next Twelve Months	$ 107
Other Commitment, Due in Second Year	82
Other Commitment, Due in Third Year	10
Other Commitment, Due in Fourth Year	0
Other Commitment, Due in Fifth Year	0
Other Commitment, Due Thereafter	$ 0

Commitments And Contingencies76

Commitments And Contingencies (Future Minimum Lease Commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments And Contingencies [Line Items]
Operating Leases, Rent Expense	$ 59	$ 58	$ 66
Year 1 Minimum Lease Commitments	26
Year 2 Minimum Lease Commitments	24
Year 3 Minimum Lease Commitments	23
Year 4 Minimum Lease Commitments	18
Year 5 Minimum Lease Commitments	4
Thereafter	$ 11
Lease Payments Discontinued Operations [Member]
Commitments And Contingencies [Line Items]
Operating Leases, Rent Expense			$ 9

Commitments And Contingencies77

Commitments And Contingencies (Future Minimum Transportation Fees) (Details) $ in Millions	Dec. 31, 2016USD ($)
Commitments and Contingencies Disclosure [Abstract]
Year 1 Transportation Agreements	$ 453
Year 2 Transportation Agreements	463
Year 3 Transportation Agreements	469
Year 4 Transportation Agreements	459
Year 5 Transportation Agreements	409
Thereafter	$ 694

Related Party Transactions (Nar

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

Major Customers (Consolidated O

Major Customers (Consolidated Oil, NGL And Gas Revenues) (Details) - Oil And Gas Revenue [Member]	12 Months Ended
	Dec. 31, 2016Rate	Dec. 31, 2015Rate	Dec. 31, 2014Rate
Vitol, Inc. [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	18.00%	9.00%
Plains Marketing LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	22.00%	29.00%
Occidental Energy Marketing Inc [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	18.00%	16.00%
Enterprise Products Partners L.P. [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%	12.00%	13.00%

Major Customers Major Customers

Major Customers Major Customers (Sales of Purchased Oil and Gas (Details)	12 Months Ended
	Dec. 31, 2016Rate	Dec. 31, 2015Rate	Dec. 31, 2014Rate
Occidental Energy Marketing Inc [Member] | Sales of Purchased Oil and Gas [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	18.00%	0.00%
Plains Marketing LP [Member] | Sales of Purchased Oil and Gas [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	18.00%	0.00%
Exxon Mobil [Member] | Sales of Purchased Oil and Gas [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	9.00%	0.00%
BP Corporation North America [Member] | Sales of Purchased Oil and Gas [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	13.00%	0.00%	0.00%
Valero Marketing and Supply Company [Member] | Sales of Purchased Oil and Gas [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%	37.00%	61.00%
Lonestar/Oneok [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%	9.00%	16.00%

Interest And Other Income (Inte

Interest And Other Income (Interest And Other Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest and Other Income [Abstract]
Interest income	$ 22	$ 3	$ 0
Deferred compensation plan income	3	4	3
Equity interest in income (loss) of EFS Midstream	0	5	13
Other income	7	10	10
Total interest and other income	$ 32	$ 22	$ 26

Other Expense (Schedule Of Comp

Other Expense (Schedule Of Components Of Other Expense) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Transportation commitment charge	[1]	$ 109	$ 53	$ 46
Idle Rig Expense		64	92	7
Third-party income (loss) from vertical integration services		54	34	16
Tangible Asset Impairment Charges	[2]	8	86	8
Restructuring and Related Cost, Incurred Cost		4	23	0
Other		49	27	29
Total other expense		288	315	106
GrossRevenuesIncludedInThirdPartyIncomeFromVerticalIntegrationServices		147	298	374
GrossExpensesIncludedInThirdPartyIncomeFromVerticalIntegrationServices		201	332	390
Inventory [Member]
Tangible Asset Impairment Charges		$ 8	$ 71	$ 8
[1]	Primarily represents firm transportation payments on excess pipeline capacity commitments.
[2]	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, 2016, 2015 and 2014, these net losses include $147 million, $298 million and $374 million of gross vertical integration revenues, respectively, and $201 million, $332 million and $390 million of total vertical integration costs and expenses, respectively.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Payments for income taxes, net of tax refunds received	$ (66)	$ 43	$ 22
Unrecognized tax benefit recognized in period	0	$ 0	$ 21
Unrecognized Tax Benefits	$ 112

Income Taxes (Summary Of Open T

Income Taxes (Summary Of Open Tax Years, By Jurisdiction) (Details)	12 Months Ended
	Dec. 31, 2016
UNITED STATES
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,012
Various U.S. States [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,012
South Africa [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,011

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax (Provision) Benefit Allocation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income tax benefit (provision)	$ 403	$ 155	$ (556)
Income tax from discontinued operations	0	2	60
Tax benefits related to stock-based compensation	$ 1	$ 7	$ 19

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
U.S. federal	$ 22	$ (22)	$ (3)
U.S. state	2	(1)	(1)
Current income tax (provision) benefit	24	(23)	(4)
U.S. federal	375	165	(537)
U.S. state	4	13	(15)
Deferred income tax (provision) benefit	379	178	(552)
Income tax (provision) benefit	$ 403	$ 155	$ (556)

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	$ (959)	$ (421)	$ 1,597
Income (loss) from continuing operations before tax	$ (959)	$ (421)	$ 1,597
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	$ 336	$ 147	$ (559)
Income Tax Reconciliation, State and Local Income Taxes	3	8	(10)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	(3)	0	0
Income Tax Reconciliation State Tax Credits Research	4	0	0
Effective Income Tax Rate Reconciliation, Tax Credit, Research, Amount	68	0	0
Unrecognized tax benefit recognized in period	0	0	21
Income Tax Reconciliation, Other Adjustments	(5)	0	(8)
Income Tax (Expense) Benefit	$ 403	$ 155	$ (556)
Effective Income Tax Rate, Continuing Operations	42.00%	37.00%	35.00%

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Deferred Tax Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Valuation Allowance [Line Items]
Net operating loss carryforward	[1]	$ 635	$ 441
Deferred Tax Assets, Tax Credit Carryforwards, Research		107	47
Asset retirement obligations		106	102
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost		81	75
Deferred Tax Assets, Hedging Transactions		32	0
Other		30	55
Total deferred tax assets		991	720
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes		(2,184)	(1,997)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes		(204)	(227)
Net deferred hedge gains		0	(272)
Total deferred tax liabilities		(2,388)	(2,496)
Deferred Tax Liabilities, Net		(1,397)	$ (1,776)
Valuation allowances		(4)
Unrecognized Tax Benefits		112
UNITED STATES
Valuation Allowance [Line Items]
Net operating loss carryforward		1,800
COLORADO
Valuation Allowance [Line Items]
Net operating loss carryforward		150
COLORADO | Valuation Allowance, Operating Loss Carryforwards [Member]
Valuation Allowance [Line Items]
Net operating loss carryforward		92
State of Texas Tax Credits [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Research		5
United States Federal Tax Credits [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Research		76
United State Federal Minimum Tax Credits [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Research		$ 26
[1]	Net operating loss carryforwards as of December 31, 2016 consist of $1.8 billion of U.S. federal NOLs, which expire between 2032 and 2036, and $150 million of Colorado NOLs, which expire between 2027 and 2036, and are net of a $4 million valuation allowance relating to $92 million of Colorado NOLs that the Company believes will more likely than not expire unutilized.

Net Income (Loss) Per Share A89

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Operating Activities Segment [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic		$ (556)	$ (273)	$ 920
Diluted income (loss) attributable to common stockholders		(556)	(273)	920
Segment, Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations, net of tax		(556)	(266)	1,041
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic	[1]	0	0	(10)
Net Income (Loss) Available to Common Stockholders, Basic		(556)	(266)	1,031
Diluted income (loss) attributable to common stockholders		(556)	(266)	1,031
Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic		0	(7)	(111)
Diluted income (loss) attributable to common stockholders		$ 0	$ (7)	$ (111)
[1]	(a)Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so.

Net Income (Loss) Per Share A90

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Basic	166	149	144
Diluted	166	149	144