Pioneer Natural Resources (PXD) 10-Q 2 Nov 16 2016 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Trading Symbol	PXD
Entity Registrant Name	PIONEER NATURAL RESOURCES CO
Entity Central Index Key	1,038,357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		169,720,677

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents, at Carrying Value	$ 891	$ 1,391
Short-term Investments	1,733	0
Accounts receivable:
Trade, net	447	384
Due from affiliates	0	1
Income taxes receivable	26	43
Inventories	159	155
Prepaid expenses	21	17
Other current assets:
Notes receivable	0	498
Derivatives Assets, Current	172	694
Other	5	11
Total current assets	3,454	3,194
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	18,049	16,631
Unproved properties	486	169
Accumulated depletion, depreciation and amortization	(7,866)	(6,778)
Total property, plant and equipment	10,669	10,022
Long-term Investments	319	0
Goodwill	272	272
Property, Plant and Equipment, Net	1,514	1,523
Other assets:
Derivative Assets, Noncurrent	8	64
Other, net	89	79
Assets, Total	16,325	15,154
Accounts payable:
Trade	685	798
Due to affiliates	98	85
Interest payable	39	65
Income taxes payable	0	2
Current portion of long-term debt	485	448
Other current liabilities:
Derivative Liabilities, Current	7	0
Other	63	64
Total current liabilities	1,377	1,462
Long-term Debt, Excluding Current Maturities	2,726	3,207
Derivative Liabilities, Noncurrent	20	1
Deferred income taxes	1,437	1,776
Other liabilities	334	333
Stockholders' equity:
Common stock, $.01 par value	2	2
Additional paid-in capital	8,867	6,267
Treasury stock at cost	(217)	(199)
Retained earnings	1,772	2,298
Total equity attributable to common stockholders	10,424	8,368
Noncontrolling interests in consolidating subsidiaries	7	7
Total equity	10,431	8,375
Commitments and contingencies
Liabilities and Stockholders' Equity, Total	$ 16,325	$ 15,154

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	173,212,412	152,775,920
Treasury Stock, Shares	3,495,288	3,396,220

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Thousands, shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues and other income:
Oil and gas	$ 643,000	$ 557,000	$ 1,665,000	$ 1,670,000
Sales of purchased oil and gas	444,000	326,000	1,062,000	665,000
Interest and other	7,000	2,000	21,000	16,000
Derivative gains, net	91,000	573,000	(95,000)	617,000
Gain (loss) on disposition of assets, net	1,000	779,000	4,000	782,000
Total revenues and other income	1,186,000	2,237,000	2,657,000	3,750,000
Costs and expenses:
Oil and gas production	141,000	189,000	438,000	532,000
Production and ad valorem taxes	32,000	36,000	97,000	112,000
Depletion, depreciation and amortization	386,000	364,000	1,123,000	1,003,000
Purchased oil and gas	458,000	339,000	1,113,000	684,000
Impairment of oil and gas properties	0	72,000	32,000	210,000
Exploration and abandonments	19,000	25,000	96,000	79,000
General and administrative	82,000	81,000	235,000	246,000
Accretion of discount on asset retirement obligations	5,000	3,000	14,000	9,000
Interest	50,000	46,000	161,000	138,000
Other	69,000	79,000	223,000	186,000
Costs and Expenses	1,242,000	1,234,000	3,532,000	3,199,000
Income (loss) from continuing operations before income taxes	(56,000)	1,003,000	(875,000)	551,000
Income tax provision	78,000	(355,000)	362,000	(195,000)
Income from continuing operations	22,000	648,000	(513,000)	356,000
Loss from discontinued operations, net of tax	0	(2,000)	0	(6,000)
Net income			(513,000)	350,000
Net income (loss) attributable to common stockholders	$ 22,000	$ 646,000	$ (513,000)	$ 350,000
Basic earnings per share:
Income from continuing operations	$ 0.13	$ 4.29	$ (3.10)	$ 2.36
Loss from discontinued operations	0	(0.01)	0	(0.04)
Net income	0.13	4.28	(3.10)	2.32
Diluted earnings per share:
Income from continuing operations	0.13	4.28	(3.10)	2.36
Income (loss) from discontinued operations	0	(0.01)	0	(0.04)
Net income	$ 0.13	$ 4.27	$ (3.10)	$ 2.32
Weighted average shares outstanding:
Basic weighted average shares outstanding	170	149	165	149
Diluted	170	150	165	149
Dividends declared per share	$ 0.04	$ 0.04	$ 0.08	$ 0.08
Amounts attributable to common stockholders:
Net income (loss) attributable to common stockholders	$ 22,000	$ 646,000	$ (513,000)	$ 350,000

Consolidated Statement Of Equit

Consolidated Statement Of Equity - 9 months ended Sep. 30, 2016 - 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, shares at Dec. 31, 2015		149,380
Beginning Balance at Dec. 31, 2015	$ 8,375	$ 2	$ 6,267	$ (199)	$ 2,298	$ 7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, New Issues		19,838
Stock Issued During Period, Value, New Issues	2,534	$ 0	2,534
Dividends declared ($0.04 per share)	(13)				(13)
Exercise of long-term incentive plan stock options and employee stock purchases, shares		0
Exercise of long-term incentive plan stock options and employee stock purchases	7		1	6
Treasury stock purchases, shares		(197)
Treasury stock purchases	(24)			(24)
Tax benefit related to stock-based compensation	(1)		(1)
Compensation costs:
Vested compensation awards, net, shares		598
Vested compensation awards, net	0	$ 0	0
Compensation costs included in net income	66		66			0
Net loss	(513)				(513)	0
Ending Balance, shares at Sep. 30, 2016		169,717
Ending Balance at Sep. 30, 2016	$ 10,431	$ 2	$ 8,867	$ (217)	$ 1,772	$ 7

Consolidated Statement Of Equi6

Consolidated Statement Of Equity (Parenthetical) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Stockholders' Equity [Abstract]
Dividends declared per share	$ 0.04	$ 0.04	$ 0.08	$ 0.08

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ (513,000)	$ 350,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	1,123,000	1,003,000
Impairment of oil and gas properties	32,000	210,000
Impairment of Inventory and Other Property and Equipment	6,000	21,000
Exploration expenses, including dry holes	41,000	22,000
Deferred income taxes	(340,000)	146,000
Gain on disposition of assets, net	(4,000)	(782,000)
Accretion of discount on asset retirement obligations	14,000	9,000
Discontinued operations	0	(4,000)
Interest expense	11,000	14,000
Derivative related activity	628,000	(22,000)
Amortization of stock-based compensation	66,000	70,000
Other	51,000	13,000
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(64,000)	26,000
Income taxes receivable	17,000	23,000
Inventories	(7,000)	(29,000)
Prepaid expenses	(4,000)	(3,000)
Derivatives	(24,000)	0
Other current assets	1,000	(6,000)
Accounts payable	(8,000)	(266,000)
Interest payable	(26,000)	(4,000)
Income taxes payable	(2,000)	26,000
Other current liabilities	(38,000)	(28,000)
Net cash provided by operating activities	960,000	789,000
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	503,000	556,000
Business acquisition	(429,000)	0
Proceeds from Sale and Maturity of Held-to-maturity Securities	255,000	0
Purchase of investment securities	(2,300,000)	0
Additions to oil and gas properties	(1,387,000)	(1,573,000)
Additions to other assets and other property and equipment, net	(156,000)	(191,000)
Net cash used in investing activities	(3,514,000)	(1,208,000)
Cash flows from financing activities:
Principal payments on long-term debt	(455,000)	0
Proceeds from issuance of common stock, net of issuance costs	2,534,000	0
Distributions to noncontrolling interests	0	(1,000)
Exercise of long-term incentive plan stock options and employee stock purchases	7,000	6,000
Purchases of treasury stock	(24,000)	(31,000)
Tax (provision) benefits related to stock-based compensation	(1,000)	10,000
Payments of financing fees	0	(3,000)
Dividends paid	(7,000)	(6,000)
Net cash provided by (used in) financing activities	2,054,000	(25,000)
Net increase (decrease) in cash and cash equivalents	(500,000)	(444,000)
Cash and cash equivalents, beginning of period	1,391,000	1,025,000
Cash and cash equivalents, end of period	$ 891,000	$ 581,000

Organization And Nature Of Oper

Organization And Nature Of Operations	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization And Nature Of Operations	Organization and Nature of Operations Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company operating in the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeast Colorado and the West Panhandle field in the Texas Panhandle.

Basis Of Presentation

Basis Of Presentation	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis Of Presentation	Basis of Presentation Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed in or omitted from this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2015 . Certain reclassifications have been made to the 2015 financial statement and footnote amounts in order to conform to the 2016 presentation. 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. This initiative was substantially complete as of June 30, 2016. In connection therewith, during the three and nine months ended September 30, 2016, the Company recognized nil and $4 million , respectively, of restructuring charges in other expense in the accompanying consolidated statements of operations. The restructuring charges for the nine months ended September 30, 2016 included approximately $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 operations. The restructuring plan was substantially complete as of December 31, 2015. In connection therewith, during the three and nine months ended September 30, 2015, the Company recognized $9 million and $24 million , respectively, of restructuring charges in other expense in the accompanying consolidated statements of operations. As of September 30, 2016 , the Company had $2 million of restructuring liabilities recorded in other current and noncurrent liabilities in the accompanying consolidated balance sheet, primarily related to future lease obligations associated with its Denver, Colorado office. Issuance of common stock. During the first and second quarters of 2016, the Company issued 13.8 million and 6.0 million shares of common stock, respectively, and received cash proceeds of $1.6 billion and $937 million , respectively, net of associated underwriting and offering expenses. New accounting pronouncements. In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-13, "Financial Instruments - Credit Losses." 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 those fiscal years. Early adoption is permitted. 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 and for interim periods beginning the following 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 January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements. In 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 fiscal years 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. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2016
Acquisitions and Divestitures [Abstract]
Acquisition and Divestitures	Divestitures Permian Basin Acquisition. 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 $429 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-close adjustments: Assets acquired: Proved properties $ 79 Unproved properties 348 Other property and equipment 5 Liabilities assumed: Asset retirement obligations (3 ) Net assets acquired $ 429 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 $1.0 million . The operating results included in the Company's accompanying consolidated statements of operations from the date of acquisition to September 30, 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. EFS Midstream Divestiture. In July 2015, the Company sold its 50.1 percent equity interest in EFS Midstream LLC ("EFS Midstream") to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion , of which $530 million was received in cash and the remaining $501 million was in the form of a note, which was payable to the Company in July 2016. The Company recorded a net gain on the disposition of $777 million during the three and nine months ended September 30, 2015. In July 2016, the Company received the remaining cash payment of $501 million , which settled the outstanding note receivable.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	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 table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 for each of the fair value hierarchy levels: Fair Value Measurement at September 30, 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 September 30, 2016 (in millions) Assets: Commodity derivatives $ — $ 180 $ — $ 180 Deferred compensation plan assets 81 — — 81 Total assets 81 180 — 261 Liabilities: Commodity derivatives — 19 — 19 Interest rate derivatives — 8 — 8 Total liabilities — 27 — 27 Total recurring fair value measurements $ 81 $ 153 $ — $ 234 Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("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 represent 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 September 30, 2016 , the significant inputs to these asset values represented Level 1 independent active exchange market price inputs. Interest rate derivatives. The Company's interest rate derivative liabilities represent interest rate swap contracts. 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 fair value measurements represent Level 2 inputs in the hierarchy. 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.The Company recognized noncash impairment charges of $6 million and $21 million for the nine months ended September 30, 2016 and 2015 , respectively, attributable to inventory and other property and equipment. Proved oil and gas properties . As a result of the Company's proved property impairment assessments, the Company recognized noncash impairment charges to reduce the carrying values of (i) the West Panhandle field during the three months ended March 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 to their estimated fair values. The Company calculated the fair values of the West Panhandle field, the Eagle Ford Shale field and the South Texas - Other field using a discounted future cash flow model. Significant Level 3 assumptions associated with the calculations 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 estimated 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 respective Management's Price Outlooks: Management's Price Outlooks Impairment Date Fair Value Fair 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 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. 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. 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 September 30, 2016 and December 31, 2015 are as follows: September 30, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 2,052 $ 2,052 $ 275 $ 275 Current portion of long-term debt $ 485 $ 496 $ 448 $ 462 Long-term debt $ 2,726 $ 3,022 $ 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, which approximates fair value, 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 investments represent Level 2 inputs in the hierarchy. Commercial paper, corporate bonds 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, they 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 September 30, 2016 : September 30, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Deposits Total (in millions) Cash and cash equivalents $ 891 $ — $ — $ — $ 891 Short-term investments — 742 459 532 1,733 Long-term investments — — 319 — 319 $ 891 $ 742 $ 778 $ 532 $ 2,943 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.

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	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 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") West Texas Intermediate ("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 the 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 September 30, 2016 and the weighted average oil prices for those contracts: 2016 Year Ending December 31, Fourth Quarter 2017 Collar contracts: Volume (Bbl) — 6,000 Price per Bbl: Ceiling $ — $ 70.40 Floor $ — $ 50.00 Collar contracts with short puts: Volume (Bbl) (a) 112,000 94,973 Price per Bbl: Ceiling $ 75.94 $ 62.36 Floor $ 65.41 $ 49.07 Short put $ 47.03 $ 41.30 Basis swap contracts: Midland-Cushing index swap volume (Bbl) 6,630 — Price differential ($/Bbl) (b) $ (0.80 ) $ — ____________________ (a) During the nine months ended September 30, 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. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl. (b) 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 price volatility. The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of September 30, 2016 and the weighted average NGL prices for those contracts: 2016 Year Ending December 31, Fourth Quarter 2017 Propane swap contracts (a): Volume (Bbl) 6,000 — Price per Bbl $ 21.51 $ — Ethane collar contracts (b): Volume (Bbl) — 3,000 Price per Bbl: Ceiling $ — $ 11.83 Floor $ — $ 8.68 Ethane basis swap contracts (c): Volume (MMBtu) 2,768 — Price differential ($/MMBtu) $ 0.91 $ — ____________________ (a) Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas posted prices. (b) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. (c) Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. 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 2,768 MMBtu per day, which is equivalent to 1,000 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 the 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 September 30, 2016 and the weighted average gas prices for those contracts: 2016 Year Ending December 31, Fourth Quarter 2017 2018 Swap contracts: Volume (MMBtu) 70,000 — — Price per MMBtu $ 4.06 $ — $ — Collar contracts with short puts: Volume (MMBtu) (a) 180,000 130,000 50,000 Price per MMBtu: Ceiling $ 4.01 $ 3.39 $ 3.40 Floor $ 3.24 $ 2.85 $ 2.75 Short put $ 2.78 $ 2.41 $ 2.25 Basis swap contracts: Gulf Coast index swap volume (b) 10,000 — — Price differential ($/MMBtu) $ — $ — $ — Mid-Continent index swap volume (b) 15,000 45,000 — Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ — Permian Basin index swap volume (c) 34,946 9,863 — Price differential ($/MMBtu) $ 0.41 $ 0.37 $ — ____________________ (a) During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu. (b) Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts. (c) Represent 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 September 30, 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. As of September 30, 2016 , the Company was party to derivative swap contracts for 1,000 Bbls per day of diesel for 2017 at an average per Bbl fixed price of $60.48 . Interest rate derivative activities. As of September 30, 2016 , the Company was a party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 to December 2027 in exchange for paying a weighted average fixed interest rate of 1.94 percent on a notional amount of $250 million on December 15, 2017. Tabular disclosure of derivative financial instruments . All of the Company's derivatives are accounted for as non-hedge derivatives 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 September 30, 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 $ 190 $ (18 ) $ 172 Commodity price derivatives Derivatives - noncurrent $ 11 $ (3 ) 8 $ 180 Liability Derivatives: Commodity price derivatives Derivatives - current $ 25 $ (18 ) $ 7 Commodity price derivatives Derivatives - noncurrent $ 15 $ (3 ) 12 Interest rate derivatives Derivatives - noncurrent $ 8 $ — 8 $ 27 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 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 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 Location of Gain / (Loss) Recognized in Three Months Ended Nine Months Ended Hedging Instruments Earnings on Derivatives 2016 2015 2016 2015 (in millions) Commodity price derivatives Derivative gains (losses), net $ 91 $ 575 $ (87 ) $ 614 Interest rate derivatives Derivative gains (losses), net — (2 ) (8 ) 3 Total $ 91 $ 573 $ (95 ) $ 617

Exploratory Costs

Exploratory Costs	9 Months Ended
	Sep. 30, 2016
Exploratory Cost Disclosure [Abstract]
Exploratory Costs	Exploratory Costs The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense. The following table reflects the Company's capitalized exploratory well and project activity during the three and nine months ended September 30, 2016 : Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 (in millions) Beginning capitalized exploratory costs $ 357 $ 306 Additions to exploratory costs pending the determination of proved reserves 328 991 Reclassification due to determination of proved reserves (286 ) (898 ) Exploratory well costs charged to exploration expense (1 ) (1 ) Ending capitalized exploratory costs $ 398 $ 398 The following table provides an aging, as of September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 396 $ 303 More than one year 2 3 $ 398 $ 306 Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year 1 1 The well that was suspended for a period greater than one year as of September 30, 2016 is in the Eagle Ford Shale area. The Company expects to complete this well in 2017.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-term Debt Credit facility. The Company's long-term debt consists of senior notes, a revolving corporate credit facility (the "Credit Facility") and the effects of issuance costs, issuance discounts and net deferred fair value hedge losses. The Credit Facility is maintained with a syndicate of financial institutions and has aggregate loan commitments of $1.5 billion that expire in August 2020. As of September 30, 2016 , the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants. Senior notes. 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, with an outstanding debt principal balance of $485 million , will mature in March 2017 and are classified as current in the accompanying consolidated balance sheets as of September 30, 2016 .

Incentive Plans

Incentive Plans	9 Months Ended
	Sep. 30, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Incentive Plans	Incentive Plans Stock-based compensation For the three and nine months ended September 30, 2016 , the Company recorded $31 million and $84 million , respectively, of stock-based compensation expense for all plans, as compared to $26 million and $87 million for the same respective periods in 2015 . As of September 30, 2016 , there was $138 million of unrecognized compensation expense related to unvested share-based compensation plan awards, including $36 million attributable to stock-based awards that are expected to be settled on their vesting date in cash, rather than in equity shares ("Liability Awards"). The unrecognized compensation expense will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of September 30, 2016 and December 31, 2015 , accounts payable – due to affiliates included $17 million and $16 million , respectively, of liabilities attributable to Liability Awards. The following table summarizes the activity that occurred during the nine months ended September 30, 2016 for each type of share-based incentive award issued by Pioneer: Restricted Stock Equity Awards Restricted Stock Liability Awards Performance Units Stock Options Outstanding as of December 31, 2015 1,081,650 271,031 148,547 199,058 Awards granted 520,980 180,383 104,114 — Awards vested (459,833 ) (141,441 ) (8,670 ) — Awards forfeited (43,996 ) (14,067 ) (4,821 ) — Outstanding as of September 30, 2016 1,098,801 295,906 239,170 199,058

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The following table summarizes the Company's asset retirement obligation activity during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Beginning asset retirement obligations $ 281 $ 187 $ 285 $ 189 Liabilities assumed in acquisitions 3 — 3 — New wells placed on production — 1 — 2 Liabilities settled (8 ) (9 ) (21 ) (18 ) Accretion of discount 5 3 14 9 Ending asset retirement obligations $ 281 $ 182 $ 281 $ 182 The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of both September 30, 2016 and December 31, 2015 , the current portion of the Company's asset retirement obligations was $40 million .

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	Commitments and Contingencies The Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company does not believe these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

Interest And Other Income

Interest And Other Income	9 Months Ended
	Sep. 30, 2016
Interest and Other Income [Abstract]
Interest And Other Income	Interest and Other Income The following table provides the components of the Company's interest and other income for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Interest income $ 5 $ 2 $ 14 $ 2 Deferred compensation plan income — — 2 4 Equity interest in income of EFS Midstream (a) — — — 5 Other income 2 — 5 5 Total interest and other income $ 7 $ 2 $ 21 $ 16 ____________________ (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	9 Months Ended
	Sep. 30, 2016
Other Expense [Abstract]
Other Expense	Other Expense The following table provides the components of the Company's other expense for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Transportation commitment charges (a) $ 27 $ 11 $ 77 $ 38 Loss from vertical integration services (b) 17 20 46 16 Idle drilling and well service equipment charges (c) 10 22 42 73 Terminated drilling rig charges (d) — — 15 — Impairment of inventory and other property and equipment (e) 1 13 6 21 Restructuring charges (f) — 9 4 24 Other 14 4 33 14 Total other expense $ 69 $ 79 $ 223 $ 186 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and 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 and nine months ended September 30, 2016 , these vertical integration net margins included $19 million and $144 million , respectively, of revenues and $36 million and $190 million , respectively, of costs and expenses. For the same respective periods in 2015, these vertical integration net margins included $66 million and $264 million of revenues and $86 million and $280 million of costs and expenses. (c) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations. (d) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities. (e) Primarily represents charges to reduce excess material and supplies inventories to their market values. See Note D for additional information on the fair value of materials and supplies inventory. (f) Represents costs associated with the Company's restructuring of its pressure pumping operations in South Texas in 2016 and its operations in Colorado in 2015. See Note B for additional information on the restructuring charges.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company's income tax benefit attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Current tax benefit (provision) $ 22 $ (48 ) $ 22 $ (49 ) Deferred tax benefit (provision) 56 (307 ) 340 (146 ) Income tax benefit (provision) $ 78 $ (355 ) $ 362 $ (195 ) For the three and nine months ended September 30, 2016 , the Company's effective tax rates, excluding income attributable to noncontrolling interests, were 140 percent and 41 percent , respectively, as compared to an effective rate of 35 percent for each of the the same respective periods in 2015 . The Company's effective tax rates for the three and nine months ended September 30, 2016 differ from the U.S. statutory rate of 35 percent primarily due to recognizing research and experimental expenditures credits of $59 million in the third quarter of 2016, and, to a lesser extent, state income tax apportionments and nondeductible expenses. 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 September 30, 2016, the Company had unrecognized tax benefits of $94 million resulting from research and experimental expenditures related to horizontal drilling and completions innovations. If all of, 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 September 2017. There were no unrecognized tax benefits as of December 31, 2015. The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2013 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2010. As of September 30, 2016 , no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

Net Income Per Share

Net Income Per Share	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Net Income Per Share	Net Income (Loss) Per Share The following table reconciles the Company's income (loss) from continuing operations to basic and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Income (loss) from continuing operations $ 22 $ 648 $ (513 ) $ 356 Participating basic earnings — (6 ) — (3 ) Basic and diluted income (loss) from continuing operations $ 22 $ 642 (513 ) 353 Basic and diluted loss from discontinued operations $ — $ (2 ) $ — $ (6 ) Basic and diluted net income (loss) attributable to common stockholders $ 22 $ 640 $ (513 ) $ 347 Basic and diluted weighted average common shares outstanding were 170 million and 165 million , respectively, for the three and nine months ended September 30, 2016 . Basic weighted average common shares outstanding were 149 million for both the three and nine months ended September 30, 2015 , and diluted weighted average shares outstanding were 150 million and 149 million for the three and nine months ended September 30, 2015 , respectively.

Basis Of Presentation (Policies

Basis Of Presentation (Policies)	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Presentation	Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed in or omitted from this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2015 . Certain reclassifications have been made to the 2015 financial statement and footnote amounts in order to conform to the 2016 presentation.
New Accounting Pronouncements, Policy [Policy Text Block]	New accounting pronouncements. In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-13, "Financial Instruments - Credit Losses." 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 those fiscal years. Early adoption is permitted. 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 and for interim periods beginning the following 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 January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements. In 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 fiscal years 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. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2016
Acquisitions and Divestitures [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	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-close adjustments: Assets acquired: Proved properties $ 79 Unproved properties 348 Other property and equipment 5 Liabilities assumed: Asset retirement obligations (3 ) Net assets acquired $ 429

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of assets and liabilities measured at fair value on a recurring basis	The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 for each of the fair value hierarchy levels: Fair Value Measurement at September 30, 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 September 30, 2016 (in millions) Assets: Commodity derivatives $ — $ 180 $ — $ 180 Deferred compensation plan assets 81 — — 81 Total assets 81 180 — 261 Liabilities: Commodity derivatives — 19 — 19 Interest rate derivatives — 8 — 8 Total liabilities — 27 — 27 Total recurring fair value measurements $ 81 $ 153 $ — $ 234
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 respective Management's Price Outlooks: Management's Price Outlooks Impairment Date Fair Value Fair 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
Schedule of carrying values and 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 September 30, 2016 and December 31, 2015 are as follows: September 30, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 2,052 $ 2,052 $ 275 $ 275 Current portion of long-term debt $ 485 $ 496 $ 448 $ 462 Long-term debt $ 2,726 $ 3,022 $ 3,207 $ 3,206
Cash, Cash Equivalents and Investments [Table Text Block]	The following table provides the components of the Company's cash and cash equivalents and investments as of September 30, 2016 : September 30, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Deposits Total (in millions) Cash and cash equivalents $ 891 $ — $ — $ — $ 891 Short-term investments — 742 459 532 1,733 Long-term investments — — 319 — 319 $ 891 $ 742 $ 778 $ 532 $ 2,943

Derivative Financial Instrume25

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of 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 September 30, 2016 and the weighted average oil prices for those contracts: 2016 Year Ending December 31, Fourth Quarter 2017 Collar contracts: Volume (Bbl) — 6,000 Price per Bbl: Ceiling $ — $ 70.40 Floor $ — $ 50.00 Collar contracts with short puts: Volume (Bbl) (a) 112,000 94,973 Price per Bbl: Ceiling $ 75.94 $ 62.36 Floor $ 65.41 $ 49.07 Short put $ 47.03 $ 41.30 Basis swap contracts: Midland-Cushing index swap volume (Bbl) 6,630 — Price differential ($/Bbl) (b) $ (0.80 ) $ — ____________________ (a) During the nine months ended September 30, 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. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl. (b) Represents the basis differential between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma.
Schedule of NGL derivative volumes and weighted average prices	The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of September 30, 2016 and the weighted average NGL prices for those contracts: 2016 Year Ending December 31, Fourth Quarter 2017 Propane swap contracts (a): Volume (Bbl) 6,000 — Price per Bbl $ 21.51 $ — Ethane collar contracts (b): Volume (Bbl) — 3,000 Price per Bbl: Ceiling $ — $ 11.83 Floor $ — $ 8.68 Ethane basis swap contracts (c): Volume (MMBtu) 2,768 — Price differential ($/MMBtu) $ 0.91 $ — ____________________ (a) Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas posted prices.
Schedule of gas derivative volume and weighted average prices	The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of September 30, 2016 and the weighted average gas prices for those contracts: 2016 Year Ending December 31, Fourth Quarter 2017 2018 Swap contracts: Volume (MMBtu) 70,000 — — Price per MMBtu $ 4.06 $ — $ — Collar contracts with short puts: Volume (MMBtu) (a) 180,000 130,000 50,000 Price per MMBtu: Ceiling $ 4.01 $ 3.39 $ 3.40 Floor $ 3.24 $ 2.85 $ 2.75 Short put $ 2.78 $ 2.41 $ 2.25 Basis swap contracts: Gulf Coast index swap volume (b) 10,000 — — Price differential ($/MMBtu) $ — $ — $ — Mid-Continent index swap volume (b) 15,000 45,000 — Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ — Permian Basin index swap volume (c) 34,946 9,863 — Price differential ($/MMBtu) $ 0.41 $ 0.37 $ — ____________________ (a) During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu. (b) Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts. (c) Represent 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	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 September 30, 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 $ 190 $ (18 ) $ 172 Commodity price derivatives Derivatives - noncurrent $ 11 $ (3 ) 8 $ 180 Liability Derivatives: Commodity price derivatives Derivatives - current $ 25 $ (18 ) $ 7 Commodity price derivatives Derivatives - noncurrent $ 15 $ (3 ) 12 Interest rate derivatives Derivatives - noncurrent $ 8 $ — 8 $ 27 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	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 Location of Gain / (Loss) Recognized in Three Months Ended Nine Months Ended Hedging Instruments Earnings on Derivatives 2016 2015 2016 2015 (in millions) Commodity price derivatives Derivative gains (losses), net $ 91 $ 575 $ (87 ) $ 614 Interest rate derivatives Derivative gains (losses), net — (2 ) (8 ) 3 Total $ 91 $ 573 $ (95 ) $ 617

Exploratory Costs (Tables)

Exploratory Costs (Tables)	9 Months Ended
	Sep. 30, 2016
Exploratory Cost Disclosure [Abstract]
Capitalized exploratory well and project activity	The following table reflects the Company's capitalized exploratory well and project activity during the three and nine months ended September 30, 2016 : Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 (in millions) Beginning capitalized exploratory costs $ 357 $ 306 Additions to exploratory costs pending the determination of proved reserves 328 991 Reclassification due to determination of proved reserves (286 ) (898 ) Exploratory well costs charged to exploration expense (1 ) (1 ) Ending capitalized exploratory costs $ 398 $ 398
Capitalized Exploratory Costs And The Number Of Projects For Which Exploratory Costs Have Been Capitalized	The following table provides an aging, as of September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 396 $ 303 More than one year 2 3 $ 398 $ 306 Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year 1 1

Incentive Plans (Tables)

Incentive Plans (Tables)	9 Months Ended
	Sep. 30, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Schedule of Share Based Incentive Award Activity	The following table summarizes the activity that occurred during the nine months ended September 30, 2016 for each type of share-based incentive award issued by Pioneer: Restricted Stock Equity Awards Restricted Stock Liability Awards Performance Units Stock Options Outstanding as of December 31, 2015 1,081,650 271,031 148,547 199,058 Awards granted 520,980 180,383 104,114 — Awards vested (459,833 ) (141,441 ) (8,670 ) — Awards forfeited (43,996 ) (14,067 ) (4,821 ) — Outstanding as of September 30, 2016 1,098,801 295,906 239,170 199,058

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Schedule of asset retirement obligations	The following table summarizes the Company's asset retirement obligation activity during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Beginning asset retirement obligations $ 281 $ 187 $ 285 $ 189 Liabilities assumed in acquisitions 3 — 3 — New wells placed on production — 1 — 2 Liabilities settled (8 ) (9 ) (21 ) (18 ) Accretion of discount 5 3 14 9 Ending asset retirement obligations $ 281 $ 182 $ 281 $ 182

Interest And Other Income (Tabl

Interest And Other Income (Tables)	9 Months Ended
	Sep. 30, 2016
Interest and Other Income [Abstract]
Components of interest and other income	The following table provides the components of the Company's interest and other income for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Interest income $ 5 $ 2 $ 14 $ 2 Deferred compensation plan income — — 2 4 Equity interest in income of EFS Midstream (a) — — — 5 Other income 2 — 5 5 Total interest and other income $ 7 $ 2 $ 21 $ 16 ____________________ (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)	9 Months Ended
	Sep. 30, 2016
Other Expense [Abstract]
Schedule of components of other expense	The following table provides the components of the Company's other expense for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Transportation commitment charges (a) $ 27 $ 11 $ 77 $ 38 Loss from vertical integration services (b) 17 20 46 16 Idle drilling and well service equipment charges (c) 10 22 42 73 Terminated drilling rig charges (d) — — 15 — Impairment of inventory and other property and equipment (e) 1 13 6 21 Restructuring charges (f) — 9 4 24 Other 14 4 33 14 Total other expense $ 69 $ 79 $ 223 $ 186 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and 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 and nine months ended September 30, 2016 , these vertical integration net margins included $19 million and $144 million , respectively, of revenues and $36 million and $190 million , respectively, of costs and expenses. For the same respective periods in 2015, these vertical integration net margins included $66 million and $264 million of revenues and $86 million and $280 million of costs and expenses. (c) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations. (d) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities. (e) Primarily represents charges to reduce excess material and supplies inventories to their market values. See Note D for additional information on the fair value of materials and supplies inventory. (f) Represents costs associated with the Company's restructuring of its pressure pumping operations in South Texas in 2016 and its operations in Colorado in 2015. See Note B for additional information on the restructuring charges.

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income tax (provisions) benefits attributable to income from continuing operations	The Company's income tax benefit attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Current tax benefit (provision) $ 22 $ (48 ) $ 22 $ (49 ) Deferred tax benefit (provision) 56 (307 ) 340 (146 ) Income tax benefit (provision) $ 78 $ (355 ) $ 362 $ (195 )

Net Income Per Share (Tables)

Net Income Per Share (Tables)	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Reconciliation of earnings attributable to common stockholders, basic and diluted	The following table reconciles the Company's income (loss) from continuing operations to basic and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in millions) Income (loss) from continuing operations $ 22 $ 648 $ (513 ) $ 356 Participating basic earnings — (6 ) — (3 ) Basic and diluted income (loss) from continuing operations $ 22 $ 642 (513 ) 353 Basic and diluted loss from discontinued operations $ — $ (2 ) $ — $ (6 ) Basic and diluted net income (loss) attributable to common stockholders $ 22 $ 640 $ (513 ) $ 347

Basis Of Presentation Basis of

Basis Of Presentation Basis of Presentation (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2016	Sep. 30, 2015
Summary Of Significant Accounting Policies [Line Items]
Stock Issued During Period, Shares, New Issues	6	13.8
Proceeds from issuance of common stock, net of issuance costs	$ 937	$ 1,600	$ 2,534	$ 0

Basis Of Presentation Basis o34

Basis Of Presentation Basis of Presentation (Restructuring) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Restructuring Cost and Reserve [Line Items]
Restructuring Charges	$ 0	$ 9	$ 4	$ 24
Restructuring Reserve	$ 2		2
Employee Severance [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Charges			3
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Charges			$ 1

Acquisitions and Divestitures A

Acquisitions and Divestitures Acquisitions and Divestitures (Business Combination) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)aBoe	Sep. 30, 2015USD ($)
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired	$ 429	$ 0
Permian Basin [Member]
Business Acquisition [Line Items]
Oil and gas acres acquired | a	28,000
Production, Barrels of Oil Equivalents | Boe	1,400
Payments to Acquire Businesses, Net of Cash Acquired	$ 429
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	348
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Buildings	5
AssetRetirementObligationLiabilitiesAcquiredInBusinessCombination	(3)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	429
Business Acquisition, Transaction Costs	$ 1

Acquisitions and Divestitures36

Acquisitions and Divestitures (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Ownership Percentage			50.10%
Equity Method Investment, Net Sales Proceeds		$ 1,000
Equity Method Investment, Realized Gain (Loss) on Disposal		777
Proceeds Received Prior Year [Member]
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Net Sales Proceeds		530
Proceeds Received Current Year [Member]
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Net Sales Proceeds	$ 501
Proceeds To Be Received In Future Year [Member] [Member]
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Net Sales Proceeds		$ 501

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) $ in Millions	Sep. 30, 2016USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	$ 81
Assets, Fair Value Disclosure	261
Liabilities, Fair Value Disclosure	27
Recurring Measurements, (Fair Value, Total)	234
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	81
Assets, Fair Value Disclosure	81
Liabilities, Fair Value Disclosure	0
Recurring Measurements, (Fair Value, Total)	81
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
Assets, Fair Value Disclosure	180
Liabilities, Fair Value Disclosure	27
Recurring Measurements, (Fair Value, Total)	153
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	0
Assets, Fair Value Disclosure	0
Liabilities, Fair Value Disclosure	0
Recurring Measurements, (Fair Value, Total)	0
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	180
Derivative Liability, Fair Value, Net	19
Commodity Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	0
Derivative Liability, Fair Value, Net	0
Commodity Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	180
Derivative Liability, Fair Value, Net	19
Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	0
Derivative Liability, Fair Value, Net	0
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	8
Interest Rate Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	0
Interest Rate Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	8
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	$ 0

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Nonrecurring Fair Value Measurements) (Details) $ in Thousands		3 Months Ended					9 Months Ended
		Sep. 30, 2016USD ($)	Mar. 31, 2016USD ($)$ / MMBTU$ / bbl	Dec. 31, 2015USD ($)$ / MMBTU$ / bbl	Sep. 30, 2015USD ($)$ / MMBTU$ / bbl	Mar. 31, 2015USD ($)$ / MMBTU$ / bbl	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Tangible Asset Impairment Charges	[1]	$ 1,000			$ 13,000		$ 6,000	$ 21,000
Impairment of oil and gas properties		$ 0			$ (72,000)		$ (32,000)	(210,000)
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
Impairment of Long-Lived Assets Held-for-use			$ 32,000
West Panhandle [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group			33,000			$ 61,000
Impairment of oil and gas properties			$ (32,000)			$ (138,000)
South Texas Eagle Ford Shale [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group				$ 483,000
Impairment of oil and gas properties				$ (846,000)
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					$ 88,000			$ 88,000
Impairment of oil and gas properties					$ (72,000)
[1]	Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

Fair Value Measurements (Sche39

Fair Value Measurements (Schedule Of Carrying Values And Financial Instruments Not Carried At Fair Value) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities	$ 2,726	$ 3,207
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	2,052	275
Debt, Current	485	448
Long-term Debt, Excluding Current Maturities	2,726	3,207
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	2,052	275
Debt, Current	496	462
Long-term Debt, Excluding Current Maturities	$ 3,022	$ 3,206

Fair Value Measurements Fair 40

Fair Value Measurements Fair Value Measurements (Schedule of Cash and Cash Equivalents and Investments) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	$ 891	$ 1,391	$ 581	$ 1,025
Short-term Investments	1,733	0
Long-term Investments	319	$ 0
Cash, Cash Equivalents, and Short-term Investments	2,943
Cash and Cash Equivalents [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	891
Short-term Investments	0
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	891
Commercial Paper [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	0
Short-term Investments	742
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	742
Corporate Bond Securities [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	0
Short-term Investments	459
Long-term Investments	319
Cash, Cash Equivalents, and Short-term Investments	778
Bank Time Deposits [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	0
Short-term Investments	532
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	$ 532

Derivative Financial Instrume41

Derivative Financial Instruments (Narrative) (Details) $ in Millions	Sep. 30, 2016USD ($)bbl / d$ / bblRate
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Fixed Interest Rate | Rate	1.94%
Notional amount of debt | $	$ 250
Diesel Swap Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	60.48

Derivative Financial Instrume42

Derivative Financial Instruments (Schedule Of Oil Derivative Contracts Volume And Weighted Average Prices) (Details) $ in Millions		9 Months Ended
		Sep. 30, 2016USD ($)bbl / d$ / bbl	Oct. 28, 2016bbl / d$ / bbl
Oil contracts [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		0
Oil contracts [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		6,630
Oil contracts [Member] | Collar Contracts With Short Puts for Year 2 - Converted [Member]
Derivative [Line Items]
Premium Paid on Derivative Contract | $		$ 24
Derivative, Nonmonetary Notional Amount | bbl / d	[1]	33,000
Oil contracts [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1]	94,973
Oil contracts [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		6,000
Oil contracts [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		112,000
Oil contracts, price per bbl [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [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]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price		(1)
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for Year 2 - Converted [Member]
Derivative [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] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price		62.36
Derivative, Average Floor Price		49.07
Derivative, Notional Amount, Price Per Unit		41.30
Oil contracts, price per bbl [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price		70.40
Derivative, Average Floor Price		50
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		75.94
Derivative, Average Floor Price		65.41
Derivative, Notional Amount, Price Per Unit		47.03
Subsequent Event [Member] | Oil contracts [Member] | Collar Contracts With Short Puts for January to June Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			20,000
Subsequent Event [Member] | Oil contracts [Member] | Collar Contracts With Short Puts for July to December Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			32,000
Subsequent Event [Member] | Oil contracts [Member] | Collar Contracts With Short Puts for Year 3 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			20,000
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for January to June Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount			39
Derivative, Average Cap Price			58.99
Derivative, Average Floor Price			48.50
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for July to December Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount			40
Derivative, Average Cap Price			60.77
Derivative, Average Floor Price			50
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for Year 3 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount			40
Derivative, Average Cap Price			65.14
Derivative, Average Floor Price			50
[1]	During the nine months ended September 30, 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. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl.

Derivative Financial Instrume43

Derivative Financial Instruments Derivative Financial Instruments (Schedule of NGL Derivative Contracts Volume and Weighted Average Prices) (Details)	Sep. 30, 2016bbl / dMMBTU / d$ / MMBTU$ / bbl
NGL contract, in BBLS [Member] | Basis Swap Contracts for Current Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000
NGL contract, in BBLS [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	3,000
NGL contract, in BBLS [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
NGL contracts, price per BBL [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price | $ / bbl	11.83
Derivative, Average Floor Price | $ / bbl	8.68
NGL contracts, price per BBL [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	21.51
NGL contracts, price per BBL [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	0.91
NGL contract, MMBtu Equivalent [Member] | Basis Swap Contracts for Current Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	2,768
NGL contract, MMBtu Equivalent [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	2,768
Propane [Member] | NGL contract, in BBLS [Member] | Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	0
Propane [Member] | NGL contracts, price per BBL [Member] | Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	0

Derivative Financial Instrume44

Derivative Financial Instruments Derivative Financial Instruments (Schedule of Gas Derivative Contracts Volume and Weighted Average Prices) (Details)		Oct. 28, 2016MMBTU / d$ / MMBTU	Sep. 30, 2016MMBTU / d$ / MMBTU
Swap Contracts For Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			70,000
Swap Contracts For Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			4.06
Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			130,000
Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			3.39
Derivative, Average Floor Price			2.85
Derivative, Notional Amount, Price Per Unit			2.41
Collar Contracts With Short Puts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			50,000
Collar Contracts With Short Puts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			3.40
Derivative, Average Floor Price			2.75
Derivative, Notional Amount, Price Per Unit			2.25
Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Collar Contracts With Short Puts For Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			180,000
Collar Contracts With Short Puts For Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			4.01
Derivative, Average Floor Price			3.24
Derivative, Notional Amount, Price Per Unit			2.78
Subsequent Event [Member] | Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d		50,000
Subsequent Event [Member] | Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price		3.76
Derivative, Average Floor Price		3.06
Derivative, Notional Amount, Price Per Unit		2.50
Gulf Coast [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			10,000
Gulf Coast [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Gulf Coast [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Gulf Coast [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Gulf Coast [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Gulf Coast [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Mid-Continent [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			15,000
Mid-Continent [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		45,000
Mid-Continent [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1],[2]		0
Mid-Continent [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
Permian Basin [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			34,946
Permian Basin [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.41
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			9,863
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.37
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0
[1]	(a)During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu.
[2]	Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts.

Derivative Financial Instrume45

Derivative Financial Instruments (Schedule Of Derivative Instruments) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Assets, Current	$ 172	$ 694
Derivative Assets, Noncurrent	8	64
Derivative Liabilities, Current	7	0
Derivative Liabilities, Noncurrent	20	1
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Net	180	758
Derivative Liability, Fair Value, Net	27	1
Not Designated as Hedging Instrument [Member] | Commodity Price Derivatives [Member] | Derivatives - Current [Member]
Derivative [Line Items]
Total derivatives, Asset, Gross	190	695
Derivative Liability, Fair Value, Gross Liability	25	1
Derivative Assets Offset In Balance Sheet	(18)	(1)
Derivative Liabilities Offset In Balance Sheet	(18)	(1)
Derivative Assets, Current	172	694
Derivative Liabilities, Current	7	0
Not Designated as Hedging Instrument [Member] | Commodity Price Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Total derivatives, Asset, Gross	11	64
Derivative Liability, Fair Value, Gross Liability	15	1
Derivative Assets Offset In Balance Sheet	(3)	0
Derivative Liabilities Offset In Balance Sheet	(3)	0
Derivative Assets, Noncurrent	8	64
Derivative Liabilities, Noncurrent	12	$ 1
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	8
Derivative Liabilities Offset In Balance Sheet	0
Derivative Liabilities, Noncurrent	$ 8

Derivative Financial Instrume46

Derivative Financial Instruments (Schedule Of Derivative Obligations Under Terminated Hedge Arrangements) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative [Line Items]
Derivative gains, net	$ 91	$ 573	$ (95)	$ 617
Commodity Price Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	91	575	(87)	614
Interest Rate Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	$ 0	$ (2)	$ (8)	$ 3

Exploratory Costs (Schedule Of

Exploratory Costs (Schedule Of Capitalized Exploratory Well And Project Activity) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Beginning capitalized exploratory costs	$ 357	$ 306
Additions to exploratory costs pending the determination of proved reserves	328	991
Reclassification due to determination of proved reserves	(286)	(898)
Exploratory well costs charged to exploration expense	(1)	(1)
Ending capitalized exploratory costs	$ 398	$ 398

Exploratory Costs Exploratory W

Exploratory Costs Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2015USD ($)
Property, Plant and Equipment [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period of One Year or Less	$ 396		$ 303
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	2		3
Capitalized Exploratory Well Costs	$ 398	$ 357	$ 306
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects	1		1

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Jun. 30, 2016
Debt Instrument [Line Items]
Maximum Borrowing Capacity	$ 1,500	$ 1,500
Outstanding borrowing	0	0
Repayments of Long-term Debt		$ 455	$ 0
Five Point Eight Seven Five Percent Senior Notes Due Two Thousand Sixteen [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.875%
Repayments of Long-term Debt	$ 455
Six Point Six Five Percent Senior Notes Due Two Thousand Seventeen [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.65%	6.65%
Senior Notes	$ 485	$ 485

Incentive Plans Incentive Plans

Incentive Plans Incentive Plans (Stock-based compensation) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	$ 31	$ 26	$ 84	$ 87
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	138		$ 138
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	36		$ 36
Accounts Payable, Current	$ 17		$ 17		$ 16

Incentive Plans Incentive Pla51

Incentive Plans Incentive Plans (Share Based Incentive Award Activity) (Details) - shares	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,098,801	1,081,650
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	520,980
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(459,833)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(43,996)
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	295,906	271,031
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	180,383
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(141,441)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(14,067)
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	239,170	148,547
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	104,114
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(8,670)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(4,821)
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	199,058	199,058
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 281	$ 187	$ 285	$ 189
AssetRetirementObligationLiabilitiesAcquiredInBusinessCombination	3	0	3	0
Asset Retirement Obligation, Liabilities Incurred	0	1	0	2
Liabilities settled	(8)	(9)	(21)	(18)
Accretion of discount from continuing operations	5	3	14	9
Ending asset retirement obligations	281	$ 182	281	$ 182
Asset retirement obligations, current portions	$ 40		$ 40		$ 40

Interest And Other Income (Comp

Interest And Other Income (Components Of Interest And Other Income) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Interest and Other Income [Abstract]
Interest income		$ 5	$ 2	$ 14	$ 2
Deferred compensation plan income		0	0	2	4
Equity interest in income of unconsolidated affiliate	[1]	0	0	0	5
Other income		2	0	5	5
Total interest and other income		$ 7	$ 2	$ 21	$ 16
[1]	(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 (Schedule Of Comp

Other Expense (Schedule Of Components Of Other Expense) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Expense [Abstract]
Transportation commitment charges	[1]	$ 27	$ 11	$ 77	$ 38
Third-party vertical integration services		17	20	46	16
Above market and idle drilling and well services equipment charges	[2]	10	22	42	73
Terminated drilling rig contract charges		0	0	15	0
Tangible Asset Impairment Charges	[3]	1	13	6	21
Restructuring Charges		0	9	4	24
Other		14	4	33	14
Total other expense		69	79	223	186
GrossRevenuesIncludedInThirdPartyLossFromVerticalIntegrationServices		19	66	144	264
GrossExpensesIncludedInThirdPartyLossFromVerticalIntegrationServices		$ 36	$ 86	$ 190	$ 280
[1]	Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and 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 and nine months ended September 30, 2016, these vertical integration net margins included $19 million and $144 million, respectively, of revenues and $36 million and $190 million, respectively, of costs and expenses. For the same respective periods in 2015, these vertical integration net margins included $66 million and $264 million of revenues and $86 million and $280 million of costs and expenses.
[2]	Primarily represents firm transportation payments on excess pipeline capacity commitments.
[3]	Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax (Provisions) Benefits Attributable To Income From Continuing Operations) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Current income taxes	$ 22	$ (48)	$ 22	$ (49)
Deferred income taxes	56	(307)	340	(146)
Income tax benefit (provision)	$ 78	$ (355)	$ 362	$ (195)
Effective Tax Rate	140.00%	35.00%	41.00%	35.00%
Statutory Tax Rate	35.00%		35.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Research, Amount	$ 59		$ 59
Unrecognized Tax Benefits	$ 94		$ 94

Net Income Per Share (Reconcili

Net Income Per Share (Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement Operating Activities Segment [Line Items]
Basic income (loss) from continuing operations attributable to common stockholders	$ 22	$ 640	$ (513)	$ 347
Diluted income (loss) from continuing operations attributable to common stockholders	22	640	(513)	347
Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations attributable to parent	22	648	(513)	356
Participating Securities, Distributed and Undistributed Earnings, Basic	0	(6)	0	(3)
Basic income (loss) from continuing operations attributable to common stockholders	22	642	(513)	353
Diluted income (loss) from continuing operations attributable to common stockholders	22	642	(513)	353
Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Basic income (loss) from continuing operations attributable to common stockholders	0	(2)	0	(6)
Diluted income (loss) from continuing operations attributable to common stockholders	$ 0	$ (2)	$ 0	$ (6)

Net Income Per Share (Reconci57

Net Income Per Share (Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding) (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Basic weighted average shares outstanding	170	149	165	149
Diluted	170	150	165	149