Pioneer Natural Resources (PXD) 10-K 26 Feb 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 18, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	Pioneer Natural Resources Company
Trading Symbol	PXD
Entity Central Index Key	1,038,357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		168,369,523
Entity Shell Company	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 32,009,028,564

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 825	$ 896
Short-term investments	443	1,213
Accounts receivable:
Trade, net	694	644
Due from affiliates	120	1
Income taxes receivable	7	7
Inventories	242	212
Derivatives	52	11
Investment in affiliate	172	0
Other	25	23
Total current assets	2,580	3,007
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	21,165	20,404
Unproved properties	601	558
Accumulated depletion, depreciation and amortization	(8,218)	(9,196)
Total property, plant and equipment	13,548	11,766
Long-term investments	125	66
Goodwill	264	270
Other property and equipment, net	1,291	1,762
Other assets	95	132
Total Assets	17,903	17,003
Accounts payable:
Trade	1,441	1,174
Due to affiliates	183	108
Interest payable	53	59
Income taxes payable	2	0
Current portion of long-term debt	0	449
Derivatives	27	232
Other	112	106
Total current liabilities	1,818	2,128
Long-term debt	2,284	2,283
Derivatives	0	23
Deferred income taxes	1,152	899
Other liabilities	538	391
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 174,321,171 and 173,796,743 shares issued as of December 31, 2018 and 2017, respectively	2	2
Additional paid-in capital	9,062	8,974
Treasury stock, at cost; 4,822,069 and 3,608,132 shares as of December 31, 2018 and 2017, respectively	(423)	(249)
Retained earnings	3,470	2,547
Total equity attributable to common stockholders	12,111	11,274
Noncontrolling interest in consolidated subsidiaries	0	5
Total equity	12,111	11,279
Commitments and contingencies
Total Liabilities and Stockholders' Equity	$ 17,903	$ 17,003

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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	174,321,171	173,796,743
Treasury stock, shares	4,822,069	3,608,132

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income:
Revenue	$ 9,379
Interest and other	38	$ 53	$ 32
Derivative losses, net	(292)	(100)	(161)
Gain on disposition of assets, net	290	208	2
Revenues	9,415	5,455	3,382
Costs and expenses:
Production and ad valorem taxes	284	215	136
Depletion, depreciation and amortization	1,534	1,400	1,480
Impairment of oil and gas properties	77	285	32
Exploration and abandonments	114	106	119
General and administrative	381	326	325
Accretion of discount on asset retirement obligations	14	19	18
Interest	126	153	207
Other	849	244	288
Costs and Expenses	8,164	5,146	4,341
Income (loss) before income taxes	1,251	309	(959)
Income tax benefit (provision)	(276)	524	403
Net income (loss)	975	833	(556)
Net loss attributable to noncontrolling interests	3	0	0
Net income (loss) attributable to common stockholders	$ 978	$ 833	$ (556)
Net income (loss) per share attributable to common stockholders:
Basic (usd per share)	$ 5.71	$ 4.86	$ (3.34)
Diluted (usd per share)	$ 5.70	$ 4.85	$ (3.34)
Basic and diluted weighted average shares outstanding	171	170	166
Oil and gas
Revenues and other income:
Revenue	$ 4,991	$ 3,518	$ 2,418
Costs and expenses:
Cost of revenue	855	591	581
Sales of purchased oil and gas
Revenues and other income:
Revenue	4,388	1,776	1,091
Costs and expenses:
Cost of revenue	$ 3,930	$ 1,807	$ 1,155

Consolidated Statements Of Stoc

Consolidated Statements Of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings	Noncontrolling Interests
Beginning Balance at Dec. 31, 2015	$ 8,375	$ 2	$ 6,267	$ (199)	$ 2,298	$ 7
Beginning Balance, shares at Dec. 31, 2015		149,380
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock	$ 2,534	$ 0	2,534
Issuance of common stock, shares	19,838
Dividends declared	$ (14)				(14)
Exercise of long-term incentive plan stock options and employee stock purchases	7		1	6
Exercise of long-term incentive plan stock options and employee stock purchases, shares		98
Purchase of treasury stock	(25)			(25)
Purchase of treasury stock, shares		(200)
Tax benefits related to stock-based compensation	1		1
Compensation costs:
Vested compensation awards, net	0
Vested compensation awards, net, shares		608
Compensation costs included in net income	89		89
Net income (loss)	(556)				(556)
Ending Balance at Dec. 31, 2016	10,411	$ 2	8,892	(218)	1,728	7
Ending Balance, shares at Dec. 31, 2016		169,724
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends declared	(14)				(14)
Exercise of long-term incentive plan stock options and employee stock purchases	6		1	5
Exercise of long-term incentive plan stock options and employee stock purchases, shares		81
Purchase of treasury stock	(36)			(36)
Purchase of treasury stock, shares		(191)
Compensation costs:
Vested compensation awards, net	0
Vested compensation awards, net, shares		575
Compensation costs included in net income	79		79
Sale of noncontrolling interest	0		2			(2)
Net income (loss)	833				833
Ending Balance at Dec. 31, 2017	11,279	$ 2	8,974	(249)	2,547	5
Ending Balance, shares at Dec. 31, 2017		170,189
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends declared	(55)				(55)
Exercise of long-term incentive plan stock options and employee stock purchases	8		3	5
Exercise of long-term incentive plan stock options and employee stock purchases, shares		58
Purchase of treasury stock	(179)			(179)
Purchase of treasury stock, shares		(1,272)
Compensation costs:
Vested compensation awards, net	0
Vested compensation awards, net, shares		524
Compensation costs included in net income	85		85
Sale of noncontrolling interest			0
Sale of noncontrolling interest	(2)					(2)
Net income (loss)	975				978	(3)
Ending Balance at Dec. 31, 2018	$ 12,111	$ 2	$ 9,062	$ (423)	$ 3,470	$ 0
Ending Balance, shares at Dec. 31, 2018		169,499

Consolidated Statements Of St_2

Consolidated Statements Of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Stockholders' Equity [Abstract]
Dividends declared (usd per share)	$ 0.32	$ 0.08	$ 0.08

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 975	$ 833	$ (556)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	1,534	1,400	1,480
Impairment of oil and gas properties	77	285	32
Impairment of inventory and other property and equipment	11	2	8
Exploration expenses, including dry holes	27	22	42
Deferred income taxes	274	(519)	(379)
Gain on disposition of assets, net	(290)	(208)	(2)
Accretion of discount on asset retirement obligations	14	19	18
Interest expense	5	5	13
Derivative related activity	(270)	174	851
Amortization of stock-based compensation	85	79	89
Other	658	85	70
Change in operating assets and liabilities
Accounts receivable	(52)	(120)	(141)
Income taxes receivable	0	(4)	40
Inventories	(70)	(35)	(32)
Derivatives	0	0	(24)
Investments	4	(2)	(21)
Other current assets	(1)	3	(3)
Accounts payable	321	134	58
Interest payable	(5)	(9)	3
Other current liabilities	(55)	(45)	(46)
Net cash provided by operating activities	3,242	2,099	1,500
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	469	352	507
Payments for acquisitions	0	0	(428)
Proceeds from investments	1,373	1,467	905
Purchase of investments	(669)	(904)	(2,741)
Additions to oil and gas properties	(3,520)	(2,365)	(1,857)
Additions to other assets and other property and equipment, net	(263)	(342)	(207)
Net cash used in investing activities	(2,610)	(1,792)	(3,821)
Cash flows from financing activities:
Principal payments on long-term debt	(450)	(485)	(455)
Proceeds from issuance of common stock, net of issuance costs	0	0	2,534
Payments of other liabilities	(23)	0	0
Exercise of long-term incentive plan stock options and employee stock purchases	8	6	7
Purchases of treasury stock	(179)	(36)	(25)
Payments of financing fees	(4)	0	0
Dividends paid	(55)	(14)	(13)
Net cash provided by (used in) financing activities	(703)	(529)	2,048
Net decrease in cash and cash equivalents	(71)	(222)	(273)
Cash and cash equivalents, beginning of period	896	1,118	1,391
Cash and cash equivalents, end of period	$ 825	$ 896	$ 1,118

Organization And Nature Of Oper

Organization And Nature Of Operations	12 Months Ended
	Dec. 31, 2018
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 that explores for, develops and produces oil, natural gas liquids ("NGLs") and gas within the United States, with operations primarily in the Permian Basin in West Texas.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	NOTE 2. Summary of Significant Accounting Policies Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period's presentation. Use of estimates in the preparation of financial statements. Preparation of the Company's consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized. Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less. Investments. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are classified as short-term investments or long-term investments in the consolidated balance sheets based on their maturity dates. Investments are carried at amortized cost and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The carrying values of held-to-maturity investments are adjusted for amortization of premiums and accretion of discounts over the remaining life of the investment. Income related to these investments is recorded as interest and other income in the consolidated statements of operations. Accounts receivable. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers. T he Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. As of December 31, 2018 and 2017 , the Company's allowance for doubtful accounts totaled $2 million and $1 million , respectively. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, water, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations. During the second quarter of 2018, the Company made a voluntary change in accounting policy to account for its materials and supplies inventory on a weighted average cost basis, versus using the previous accounting policy of the first-in-first-out basis. The Company made this voluntary change in accounting policy because it believes this method is preferable, as the weighted average cost basis more closely aligns with the physical flow of material and supplies inventory and is more widely utilized in the oil and gas industry. This voluntary change in accounting policy did not have a material effect on the Company's consolidated financial statements for prior periods. As such, prior periods have not been restated. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, NGLs and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations. The components of inventories are as follows: As of December 31, 2018 2017 (in millions) Materials and supplies (a) $ 128 $ 134 Commodities 114 78 $ 242 $ 212 ____________________ (a) As of December 31, 2018 and 2017 , the Company's materials and supplies inventories were net of valuation allowances of $5 million and $5 million , respectively. Investment in affiliate. In December 2018, the Company completed the sale of its pressure pumping assets to ProPetro Holding Corp. ("ProPetro") in exchange for short-term receivables and 16.6 million shares of ProPetro's common stock, representing an ownership interest in ProPetro of approximately 16 percent as of December 31, 2018. Additionally, the Company is entitled to designate a director and an independent director to ProPetro's board of directors. Based on its ownership in ProPetro and representation on the ProPetro board of directors, the Company has determined it has the ability to exercise significant influence over the operating and financial policies of ProPetro. The Company uses the fair value option to account for its equity method investment in ProPetro. The carrying value of the Company's short-term receivables and investment in ProPetro are classified as accounts receivable – due from affiliates and investment in affiliate, respectively, in the consolidated balance sheets. See Note 4 and Note 11 for additional information. Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note 6 for additional information. The Company owns interests in 11 gas processing plants and two treating facilities. The Company is the operator of the two treating facilities and none of the gas processing plants. Two of the gas processing facilities are under construction and one of the treating facilities is not currently being used. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third-party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third-party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third-party revenues generated from the processing plants and treating facilities for the years ended December 31, 2018 , 2017 and 2016 were $78 million , $60 million and $41 million , respectively. Third-party expenses attributable to the processing plants and treating facilities for the same respective periods were $36 million , $26 million and $24 million . The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note 4 for additional information. Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time. Goodwill. Goodwill is assessed for impairment whenever it is likely that events or circumstances indicate the carrying value of a reporting unit exceeds its fair value, but no less often than annually. An impairment charge is recorded for the amount by which the carrying amount exceeds the fair value of a reporting unit in the period it is determined to be impaired. In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-04, "Simplifying the Test of Goodwill Impairment" ("ASU 2017-04"). ASU 2017-04 simplifies the quantitative goodwill impairment test by eliminating the requirement to calculate the implied fair value of goodwill (step 2 of the previous goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit's carrying value over its fair value (as measured in step 1 of the previous goodwill impairment test). ASU 2017-04 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. In July 2018, the Company elected to early adopt this update. The adoption of ASU 2017-04 had no impact on the Company's consolidated financial statements. The Company performed its annual qualitative assessment of goodwill during the third quarter of 2018 to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount. Based on the results of the assessment, the Company determined it was not likely that the carrying value of the Company's reporting unit exceeded its fair value. Other property and equipment, net. Other property and equipment is recorded at cost. The net carrying values of other property and equipment are as follows: As of December 31, 2018 (a) 2017 (a) (in millions) Land and buildings (b) $ 380 $ 469 Proved and unproved sand properties (c) 36 468 Water infrastructure (d) 343 319 Transport and field equipment (b)(e) 50 152 Information technology 143 140 Leasehold improvements 13 20 Furniture and fixtures 15 19 Construction in progress and capitalized interest (f) 311 175 $ 1,291 $ 1,762 ____________________ (a) At December 31, 2018 and 2017 , other property and equipment was net of accumulated depreciation of $854 million and $937 million , respectively. (b) The decrease from December 31, 2017 is primarily due to the Company's sale of its pressure pumping assets on December 31, 2018 . (c) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. The decrease from December 31, 2017 is primarily due to the Company's plan to close its sand mine located in Brady, Texas. Other property and equipment associated with the Brady, Texas sand mine was subject to accelerated depreciation to reduce such property and equipment to its net realizable value by its expected closure in May 2019. The accelerated depreciation associated with the planned closure is recorded to other expense in the consolidated statements of operations. See Note 3 for additional information. (d) Includes pipeline infrastructure costs and water supply wells. (e) Includes vehicles and well servicing equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, construction equipment and fishing tools that provide well services on Company-operated properties. (f) Includes capitalized costs and capitalized interest on other property and equipment not yet placed in service as of December 31, 2018 and 2017 . Construction in progress, including related capitalized interest, associated with the Company's new corporate headquarters was $217 million and $ 57 million as of December 31, 2018 and 2017 , respectively. See Note 10 for additional information. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years . Equipment, vehicles, furniture and fixtures and information technology assets are generally depreciated over two to 15 years . Water infrastructure is generally depreciated over ten to 50 years . Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method. Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the consolidated balance sheets and expenditures are classified as cash used in operating activities in the consolidated statements of cash flows. See Note 9 for additional information. Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. Issuance of common stock. In January and June of 2016, the Company issued 13.8 million and 6.0 million shares of its common stock, respectively, and realized cash proceeds of $1.6 billion and $937 million , respectively, net of associated underwriting and offering expenses. Revenue recognition. The Company recognizes revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted ASU No. 2014-09, Accounting Standards Codification ("ASC") 606, "Revenue from Contracts with Customers" ("ASC 606"), which supersedes the revenue recognition requirements in ASC 605, "Revenue Recognition" ("ASC 605"), on January 1, 2018 using the modified retrospective transition method. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting under ASC 605. The Company completed a detailed review of its revenue contracts in 2017, which represented all of the Company's revenue streams including oil, NGL and gas sales and sales of purchased oil and gas, in order to adopt the new standard beginning on January 1, 2018. The Company did not record a change to its opening retained earnings as of January 1, 2018 as there was no material change to the timing or pattern of revenue recognition due to the adoption of ASC 606. Prior to the adoption of ASC 606 on January 1, 2018, the Company recognized revenue when it was realized or realizable and earned. Revenues were considered realized or realizable and earned when: (i) persuasive evidence of an arrangement existed, (ii) delivery occurred or services had been rendered, (iii) the seller's price to the buyer was fixed or determinable and (iv) collectability was reasonably assured. The adoption of ASC 606 as of January 1, 2018 impacted the Company's results of operations as follows: Year Ended December 31, 2018 As Reported ASC 605 Effect of Change (in millions) Revenues and other income: Oil and gas $ 4,991 $ 4,784 $ 207 Costs and expenses: Oil and gas production $ 855 $ 648 $ 207 Changes in oil and gas revenues and oil and gas production costs (specifically gathering, processing and transportation costs) are due to the conclusion under the control model in ASC 606 that the third-party processor or transporter is only providing gas processing or transportation services and that the Company remains the principal owner of the commodity until sold to the ultimate purchaser. This is a change from ASC 605 where the Company historically recorded gas processing fees as a reduction of revenue recognized by the Company, as these fees were considered necessary to separate the wet gas stream into its sellable components (i.e., dry gas and individual NGL components). Under ASC 605, third-party processing and transportation companies were determined to have control of the commodities being processed and transported. As a result of adopting ASC 606, the Company has modified its presentation of revenues and expenses for these arrangements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party purchasers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the purchaser, are now presented as oil and gas production costs. See Note 13 for additional information. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate oil ("WTI") sales to a Gulf Coast or export market price and to satisfy unused gas pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. Transportation costs associated with purchases and sales of third-party oil and gas are presented on a net basis in purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are recorded as other expense in the consolidated statements of operations. See Note 15 for additional information. Derivatives. All of the Company's derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. 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 Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. The Company's credit risk related to derivatives is a counterparty's failure to perform under derivative contracts owed to the Company. 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 Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 5 for additional information. Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date. The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all of the deferred tax assets will not be realized. 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. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. See Note 16 for additional information. The Company records any tax-related interest charges as interest expense and any tax-related penalties as other expense in the consolidated statements of operations. Stock-based compensation. Stock-based compensation expense for restricted stock, restricted stock units and performance units expected to be settled in the Company's common stock ("Equity Awards") is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of estimated forfeitures, on a straight line basis over the vesting period of the respective award. The fair value of Equity Awards, except performance unit awards, is determined on the grant date or modification date, as applicable, using the prior day's closing stock price. The fair value of performance unit awards is determined using the Monte Carlo simulation model. Equity Awards are net settled by withholding shares of the Company's common stock to satisfy income tax withholding payments due upon vesting. Remaining vested shares are remitted to individual employee brokerage accounts. Shares to be delivered upon vesting of Equity Awards are made available from authorized, but unissued shares or shares held as treasury stock. Restricted stock awards expected to be settled in cash on their vesting dates, rather than in common stock ("Liability Awards"), are classified as accounts payable – due to affiliates on the consolidated balance sheets. The fair value of Liability Awards on the grant date is determined using the prior day's closing stock price. Liability Awards are marked to fair value as of each balance sheet date using the closing stock price on the balance sheet date. Changes in the fair value of Liability Awards are recorded as increases or decreases to stock-based compensation expense. Equity Awards and Liability awards participate in dividends during vesting periods and generally vest over three years . Segments. Based upon how the Company is organized and managed, the Company has one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. New accounting pronouncements. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASC 842"). ASC 842 requires lessees to recognize lease assets and lease liabilities for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This standard will be effective for the Company for interim periods beginning January 1, 2019. ASC 842 should be applied using a modified retrospective approach. The Company will elect to apply transition guidance under ASU 2018-11, "Leases (Topic 842) Targeted Improvements," in which ASC 842 is applied at the adoption date, while the comparative periods will continue to be reported in accordance with historic accounting under ASC 840, "Leases." This standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. Based on its current commitments, the Company will be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements and potentially other arrangements. The Company plans to apply certain practical expedients provided in ASC 842 that, among other things, allow entities to not reassess contracts that commenced prior to adoption and to not recognize right of use assets and lease liabilities related to short-term leases. The adoption of ASC 842 will have a material impact on the Company's consolidated balance sheets, but will not have an impact on the consolidated statements of operations or the consolidated statements of cash flows. In preparation for the adoption of the standard, the Company has developed internal controls applicable to the process used to determine financial information required to be

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions, Divestitures and Decommissioning Activities Acquisitions. During 2018 , 2017 and 2016 , the Company spent a total of $65 million , $136 million and $446 million , respectively, to acquire primarily undeveloped acreage for future exploitation and exploration activities in the Spraberry/Wolfcamp field of the Permian Basin. As part of the the 2016 acquisitions, the Company acquired approximately 28,000 net acres in the Permian Basin, with net production of approximately 1,400 barrels of oil equivalent per day ("BOEPD"), from an unaffiliated third party for $428 million . The acquisition was accounted for as a business combination. The allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date (in millions) is as follows: Assets acquired: Proved properties $ 79 Unproved properties 347 Other property and equipment 5 Liabilities assumed: Asset retirement obligations (2 ) Other liabilities (1 ) Net assets acquired $ 428 The fair value measurements of the net assets acquired in 2016 are based on inputs that are not observable in the market and, therefore, represent Level 3 inputs in the fair value hierarchy (see Note 4 for additional information). The Company calculated the fair value 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 ten percent for proved properties and seven percent for asset retirement obligations. The Company calculated the fair value of the acquired unproved properties based on the average price per acre in comparable market transactions. The operating results attributable to the acquired assets and liabilities assumed are included in the Company's consolidated statements of operations since the date of acquisition. In connection with the acquisition, the Company incurred acquisition related costs (primarily consulting, advisory and legal fees) of $1 million . Divestitures. The Company's significant divestitures are as follows: • In December 2018, the Company completed the sale of its pressure pumping assets to ProPetro in exchange for total consideration of $282 million , comprised of $110 million of short-term receivables to be paid by ProPetro during the first quarter of 2019 and 16.6 million shares of ProPetro's common stock that had a fair value of $172 million . The total consideration is a noncash investing activity as of December 31, 2018 . The Company recorded a gain of $30 million , employee-related charges of $19 million , contract termination charges of $13 million and other divestiture-related charges of $6 million associated with the sale. Additionally, the Company reduced the carrying value of goodwill by $3 million , reflecting the portion of the Company's goodwill related to the assets sold. See Note 2 and Note 11 for additional information. • In December 2018, the Company completed the sale of approximately 2,900 net acres in the Sinor Nest (Lower Wilcox) oil field in South Texas to an unaffiliated third party for net cash proceeds $105 million , after normal closing adjustments. The Company recorded a gain of $54 million associated with the sale. Additionally, the Company reduced the carrying value of goodwill by $1 million , reflecting the portion of the Company's goodwill related to the assets sold. • In August 2018, the Company completed the sale of its assets in the West Panhandle gas and liquids field to an unaffiliated third party for net cash proceeds of $170 million , after normal closing adjustments. The assets sold represent all of the Company's interests in the field, including all of its producing wells and the associated infrastructure. The Company recorded a gain of $127 million and employee-related charges of $7 million associated with the sale. Additionally, the Company reduced the carrying value of goodwill by $1 million , reflecting the portion of the Company's goodwill related to the assets sold. • In July 2018, the Company completed the sale of its gas field assets in the Raton Basin to an unaffiliated third party for net cash proceeds of $54 million , after normal closing adjustments. The Company recorded a noncash impairment charge of $77 million in June 2018 to reduce the carrying value of its Raton Basin assets to their estimated fair value less costs to sell as the assets were considered held for sale. The Company recorded a gain of $2 million associated with this divestiture. The Company also recorded other divestiture-related charges of $117 million , including $111 million of deficiency charges related to certain firm transportation contracts retained by the Company and employee-related charges of $6 million . Additionally, the Company reduced the carrying value of goodwill by $1 million , reflecting the portion of the Company's goodwill related to the assets sold. • In April 2018, the Company completed the sale of approximately 10,200 net acres in the West Eagle Ford Shale gas and liquids field to an unaffiliated third party for net cash proceeds of $100 million , after normal closing adjustments. The Company recorded a gain of $75 million associated with the sale. Additionally, the Company reduced the carrying value of goodwill by $1 million , reflecting the portion of the Company's goodwill related to the assets sold. • In April 2017, the Company completed the sale of approximately 20,500 acres in the Martin County region of the Permian Basin, with net production of approximately 1,500 BOEPD, to an unaffiliated third party for cash proceeds of $264 million . The sale resulted in a gain of $194 million . In conjunction with the divestiture, the Company reduced the carrying value of goodwill by $2 million , reflecting the portion of the Company's goodwill related to the assets sold. • Other. During 2018 , 2017 and 2016 , the Company sold other proved and unproved properties, inventory and other property and equipment and recorded net gains of $1 million , $14 million and $2 million , respectively. The net gain of $14 million for 2017 is primarily related to the sale of nonstrategic proved and unproved properties in the Permian Basin for cash proceeds of $77 million . Decommissioning activities. In November 2018, the Company announced plans to close its sand mine located in Brady, Texas and transition its proppant supply requirements to West Texas sand sources. During 2018, the Company recorded $443 million of accelerated depreciation and $7 million of employee-related charges associated with the pending shutdown. Divestiture-related and decommissioning-related charges. Divestiture-related charges, including employee-related charges, contract termination charges and other costs resulting from the Company's divestitures, are recorded as other expense in the statements of operations and as other noncash operating activities in the consolidated statements of cash flows. Obligations associated with employee-related charges are classified as accounts payable - due to affiliates in the consolidated balance sheets. Obligations associated with contract termination charges are classified as other current or noncurrent liabilities in the consolidated balance sheets. Divestiture-related and decommissioning-related obligations activity is as follows: Year Ended December 31, 2018 (in millions) Employee-related charges: Beginning employee-related obligations $ — Additions 39 Cash payments (12 ) Ending employee-related obligations 27 Contract termination charges: Beginning contract termination obligations — Additions 124 Cash payments (13 ) Ending contract termination obligations (a) 111 Total divestiture-related and decommissioning-related obligations $ 138 ______________________ (a) Includes $98 million of deficiency charges related to certain firm transportation contracts associated with the divestiture of the Company's gas field assets in the Raton Basin. These obligations were retained by the Company and are expected to be paid as follows: $42 million in 2019 , $44 million in 2020 and $12 million in 2021 .

Disclosures About Fair Value Me

Disclosures About Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The Company determines fair value based on the price that would be received from selling an asset or 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 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 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, typically reflecting management's estimate of assumptions that market participants would use in pricing the asset or liability. The fair values are therefore, determined using model-based techniques, including discounted cash flow models. Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis are as follows: Fair Value Measurements at December 31, 2018 Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value as of December 31, 2018 (in millions) Assets: Commodity derivatives $ — $ 52 $ — $ 52 Deferred compensation plan assets 82 — — 82 Investment in affiliate — 172 — 172 Total assets 82 224 — 306 Liabilities: Commodity derivatives — 27 — 27 Total liabilities — 27 — 27 Total recurring fair value measurements $ 82 $ 197 $ — $ 279 Fair Value Measurements at December 31, 2017 Using Quoted Prices in Significant Other Significant Fair Value as of December 31, 2017 (in millions) Assets: Commodity derivatives $ — $ 11 $ — $ 11 Deferred compensation plan assets 95 — — 95 Total assets 95 11 — 106 Liabilities: Commodity derivatives — 255 — 255 Total liabilities — 255 — 255 Total recurring fair value measurements $ 95 $ (244 ) $ — $ (149 ) Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts are determined using Level 2 inputs. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives using 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 include 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. The significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Investment in affiliate . The Company elected the fair value option for measuring its equity method investment in ProPetro. The fair value of its investment in ProPetro is determined using Level 2 inputs, including the quoted market price for the stock as adjusted to reflect a value discount due to the shares not being able to be sold until mid-2019. See Note 11 for additional information. Assets and liabilities measured at fair value on a nonrecurring basis. Assets and liabilities measured at fair value on a nonrecurring basis are subject to fair value adjustments in certain circumstances. The Company assesses recoverability of the carrying amount of certain assets and liabilities whenever events or changes in circumstances indicate the carrying amount of an asset or liability may not be recoverable. These assets and liabilities can include inventories, 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. Proved oil and gas properties. As a result of the the Company's proved property impairment assessments, the Company recorded noncash impairment charges to reduce the carrying values of its Raton Basin gas field assets during the year ended December 31, 2017 and the West Panhandle gas and liquids field during the year ended December 31, 2016. Impairment charges for proved oil and gas properties are recorded as impairment of oil and gas properties in the consolidated statements of operations. The Company calculated the fair values of the Raton Basin assets and West Panhandle field proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included management's longer-term commodity price outlooks ("Management's Price Outlooks") and management's outlooks for (i) production, (ii) capital expenditures, (iii) production costs 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 ten percent to determine fair value. The fair value and fair value adjustments for proved properties, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks are as follows: Fair Value Fair Value Adjustment Management's Price Outlooks Oil Gas (in millions) Raton Basin March 2017 $ 186 $ (285 ) $ 53.65 $ 3.00 West Panhandle March 2016 $ 33 $ (32 ) $ 49.77 $ 3.24 Unproved oil and gas properties. During 2016, the Company recorded a noncash impairment charge of $32 million to write-off the carrying value of its unproved royalty acreage in Alaska as a result of the operator curtailing operations in the area and Management's Price Outlooks. The impairment charges for unproved oil and gas properties are recorded as exploration and abandonments in the consolidated statements of operations. Sale of Raton Basin assets. In June 2018, the Company recognized impairment charges of $77 million to reduce the carrying value of its Raton Basin gas field assets to the agreed upon sales price for these assets, which were sold in July 2018. The impairment charges included $65 million attributable to proved oil and gas properties and $12 million of other property and equipment. These impairment charges are recorded as impairment of oil and gas properties in the consolidated statement of operations. The Company also recorded other divestiture-related charges of $111 million attributable to deficiency charges related to certain firm transportation contracts retained by the Company. The fair value of these contracts was determined using Level 2 inputs, including an annual discount rate of 4.4 percent , to discount the expected future cash flows. See Note 3 for additional information. Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets are as follows: December 31, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (in millions) Assets: Cash and cash equivalents: Cash (a) $ 775 775 $ 846 $ 846 Time deposits (a) 50 50 50 50 Total $ 825 $ 825 $ 896 $ 896 Short-term investments: Commercial paper (b) $ 53 53 $ 124 124 Corporate bonds (c) 290 288 642 640 Time deposits (b) 100 100 447 447 Total $ 443 $ 441 $ 1,213 $ 1,211 Long-term investments: Corporate bonds (c) $ 125 $ 125 $ 66 $ 66 Total $ 125 $ 125 $ 66 $ 66 Liabilities: Current portion of long-term debt (d) $ — $ — $ 449 $ 457 Long-term debt (d) $ 2,284 $ 2,374 $ 2,283 $ 2,479 ______________________ (a) Fair value approximates carrying value due to the short-term nature of the instruments. (b) Fair value is determined using Level 2 inputs. (c) Fair value is determined using Level 1 inputs. (d) Fair value is determined using Level 2 inputs. The Company's senior notes are quoted but not actively traded on major exchanges; therefore, fair value is based on periodic values as quoted on major exchanges. The Company has other financial instruments consisting primarily of receivables, 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	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments The Company utilizes commodity swap contracts, option contracts, collar contracts, collar contracts with short puts and basis swap contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness. Periodically, the Company may pay a premium to enter into commodity contracts. Premiums paid, if any, have been nominal in relation to the value of the underlying asset in the contract. The Company recognizes the nominal premium payments as an increase to the value of the derivative assets when paid. Oil production derivatives. The Company sells its oil production at the lease and the sales contracts governing such oil production are tied directly to, or are correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The Company also enters into pipeline capacity commitments in order to secure available oil transportation capacity from its areas of production to the Gulf Coast. In order to diversify the oil price it receives, the Company (i) enters into oil purchase transactions with third parties in its areas of production that are consistent with the oil prices that the Company receives at the lease, adjusted for transportation costs to the point of purchase, (ii) transports the purchased oil using its pipeline capacity to the Gulf Coast, and (iii) enters into third party sale transactions to sell the oil into the Gulf Coast refinery or international export markets at prices that are highly correlated with Brent oil prices. As a result, the Company will generally use Brent derivative contracts to manage future oil price volatility. Volumes per day associated with outstanding oil derivative contracts as of December 31, 2018 and the weighted average oil prices for those contracts are as follows: 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Brent collar contracts with short puts: Volume per day (Bbl) 15,000 15,000 15,000 15,000 Price per Bbl: Ceiling $ 89.90 $ 89.90 $ 89.90 $ 89.90 Floor $ 75.00 $ 75.00 $ 75.00 $ 75.00 Short put $ 65.00 $ 65.00 $ 65.00 $ 65.00 NGL production derivatives. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to Mont Belvieu, Texas NGL component product prices. The Company uses derivative contracts to manage the NGL component product price volatility. As of December 31, 2018 the Company did not have any NGL derivative contracts outstanding. Gas production derivatives. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("HH") gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold. Volumes per day associated with outstanding gas derivative contracts as of December 31, 2018 and the weighted average gas prices for those contracts are as follows: 2019 First Second Quarter Third Quarter Fourth Quarter Swap contracts: Volume per day (MMBtu) 102,622 50,000 50,000 16,848 Price per MMBtu $ 3.39 $ 2.94 $ 2.94 $ 2.94 Basis swap contracts: Permian Basin index swap volume per day (MMBtu) (a) 57,378 60,000 60,000 — Price differential ($/MMBtu) $ (1.47 ) $ (1.46 ) $ (1.46 ) $ — Southern California index swap volume per day (MMBtu) (b) 100,000 80,000 80,000 80,000 Price differential ($/MMBtu) $ 0.40 $ 0.31 $ 0.31 $ 0.31 Call option contracts sold: Volume per day (MMBtu) (c) 50,000 — — — Price per MMBtu $ 3.93 $ — $ — $ — ____________________ (a) The referenced basis swap contracts fix the basis differentials between the index price at which the Company sells its Permian Basin gas and the HH price used in swap contracts. (b) The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in Arizona and southern California. (c) The premium associated with selling these call option contracts was utilized to improve the swap contract prices for April through October 2019 swap volumes. Fair value. The fair value of derivative financial instruments not designated as hedging instruments is as follows: Fair Value of Derivative Instruments as of December 31, 2018 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) Asset Derivatives: Commodity price derivatives Derivatives - current $ 59 $ (7 ) $ 52 $ 52 Liability Derivatives: Commodity price derivatives Derivatives - current $ 34 $ (7 ) $ 27 $ 27 Fair Value of Derivative Instruments as of December 31, 2017 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) Asset Derivatives: Commodity price derivatives Derivatives - current $ 13 $ (2 ) $ 11 Commodity price derivatives Derivatives - noncurrent $ 3 $ (3 ) — $ 11 Liability Derivatives: Commodity price derivatives Derivatives - current $ 234 $ (2 ) $ 232 Commodity price derivatives Derivatives - noncurrent $ 26 $ (3 ) 23 $ 255 Gains (losses) recorded on derivative contracts are as follows: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recorded as Earnings on Derivatives Amount of Gain/(Loss) Recorded as Earnings on Derivatives Year Ended December 31, 2018 2017 2016 (in millions) Commodity price derivatives Derivative losses, net $ (292 ) $ (99 ) $ (174 ) Interest rate derivatives Derivative losses, net — (1 ) 13 $ (292 ) $ (100 ) $ (161 ) Net derivative assets (liabilities) by counterparty are as follows: December 31, 2018 Net Assets (Liabilities) (in millions) Macquarie Bank $ (27 ) J Aron & Company 2 Bank of Montreal 2 JP Morgan Chase 2 Societe Generale 46 $ 25 See Note 2 for additional information.

Exploratory Well Costs

Exploratory Well Costs	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Exploratory Well Costs	Exploratory Well Costs The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are classified as proved properties in the consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are recorded as exploration and abandonments expense. Capitalized exploratory well project activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Beginning capitalized exploratory well costs $ 505 $ 323 $ 306 Additions to exploratory well costs pending the determination of proved reserves 2,585 1,956 1,387 Reclassification due to determination of proved reserves (2,557 ) (1,764 ) (1,369 ) Disposition of assets (1 ) — — Exploratory well costs charged to exploration and abandonment expense (23 ) (10 ) (1 ) Ending capitalized exploratory well costs $ 509 $ 505 $ 323 Aging 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 are as follows: As of December 31, 2018 2017 2016 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 509 $ 493 $ 318 More than one year — 12 5 $ 509 $ 505 $ 323 Number of projects with exploratory well costs that have been suspended for a period greater than one year — 7 3

Long-term Debt and Interest Exp

Long-term Debt and Interest Expense	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-term Debt and Interest Expense	Long-term Debt and Interest Expense The components of long-term debt, including the effects of issuance costs and issuance discounts, are as follows: December 31, 2018 2017 (in millions) Outstanding debt principal balances: 6.875% senior notes due 2018 (a) $ — $ 450 7.50% senior notes due 2020 450 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 2,300 2,750 Issuance costs and discounts (16 ) (18 ) Long-term debt 2,284 2,732 Less current portion of long-term debt (a) — 449 Long-term debt $ 2,284 $ 2,283 ______________________________ (a) The 6.875% senior notes, net of $106 thousand of unamortized issuance costs and discounts, are classified as current in the consolidated balance sheet as of December 31, 2017. Credit facility. During October 2018, the Company entered into a Credit Agreement dated as of October 24, 2018 (the "Credit Facility") with a syndicate of financial institutions (the "Syndicate"), primarily to extend the maturity of the Credit Facility from August 2020 to October 2023, while maintaining aggregate loan commitments of $1.5 billion . The Company accounted for the entry into the Credit Facility as a modification of the prior agreement and capitalized the debt issuance costs along with those unamortized issuance costs that remained from the issuance of the prior agreement. As of December 31, 2018 , the Company had no outstanding borrowings under the Credit Facility. Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Revolving loans represent loans made ratably by the Syndicate in accordance with their respective commitments under the Credit Facility and bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently 0.25 percent based upon the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently 1.25 percent and is also determined by the Company's debt rating. Swing line loans represent loans made by a subset of the lenders in the Syndicate and may not exceed $150 million . Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent . The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.15 percent ). Borrowings under the Credit Facility are general unsecured obligations. The Credit Facility requires the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed 0.65 to 1.0. As of December 31, 2018 , the Company was in compliance with all of its debt covenants. Senior notes. The Company's 6.875% senior notes (the " 6.875% Senior Notes") and 6.65% senior notes (the " 6.65% Senior Notes"), with debt principal balances of $450 million and $485 million , respectively, matured and were repaid in May 2018 and March 2017, respectively. The Company funded the repayments with cash on hand. The 6.875% Senior Notes were classified as current in the consolidated balance sheet as of December 31, 2017 . The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable semiannually. Principal payments scheduled to be made on the Company's long-term debt are as follows (in millions): 2019 $ — 2020 $ 450 2021 $ 500 2022 $ 600 2023 $ — Thereafter $ 750 Interest expense activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Cash payments for interest $ 133 $ 164 $ 196 Amortization of issuance discounts 1 1 9 Amortization of capitalized loan fees 4 4 4 Net changes in accruals (6 ) (9 ) 2 Interest incurred 132 160 211 Less capitalized interest (6 ) (7 ) (4 ) $ 126 $ 153 $ 207

Incentive Plans

Incentive Plans	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Incentive Plans	Incentive Plans Deferred compensation retirement plan. The Company's deferred compensation retirement plan allows for qualified officers and certain key employees of the Company to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company provides a matching contribution of 100 percent of the officer's and key employee's contribution limited up to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company's matching contributions were $3 million for each of the years ended December 31, 2018 , 2017 and 2016 , respectively. 401(k) plan. The Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute up to 80 percent of their annual base salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's annual base salary (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four -year period that begins on the participant's date of hire. Beginning in February 2018, eligible employees are automatically enrolled in the 401(k) Plan at a contribution rate of five percent of the employee's annual base salary, unless the employee opts out of participation or makes an alternate election within 30 days of becoming eligible for participation. During the years ended December 31, 2018 , 2017 and 2016 , the Company recorded compensation expense of $36 million , $25 million and $23 million , respectively, as a result of Matching Contributions. Stock-based compensation costs. The Company records stock-based compensation expense ratably over the vesting periods of the Company's stock-based compensation awards using the awards' fair value. The Company maintains two plans providing for stock-based compensation: the Amended and Restated 2006 Long-Term Incentive Plan ("LTIP") and the Employee Stock Purchase Plan ("ESPP"). Long-Term Incentive Plan. The LTIP provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The number of shares available for grant pursuant to awards under the LTIP is as follows: As of December 31, 2018 Approved and authorized awards 12,600,000 Awards issued under plan (7,746,616 ) Awards available for future grant 4,853,384 Employee Stock Purchase Plan. The ESPP allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's base salary (subject to certain ESPP limits) during the eight -month offering period (January 1 to August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing sales price is lower. The number of shares available for issuance under the ESPP is as follows: As of December 31, 2018 Approved and authorized shares 1,250,000 Shares issued (1,002,433 ) Shares available for future issuance 247,567 Stock-based compensation expense and the associated income tax benefit are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Restricted stock - Equity Awards $ 65 $ 60 $ 66 Restricted stock - Liability Awards 17 24 24 Performance unit awards 18 17 21 ESPP 2 2 2 $ 102 $ 103 $ 113 Income tax benefit $ 17 $ 19 $ 34 As of December 31, 2018 , there was $80 million of unrecorded stock-based compensation expense related to unvested share-based compensation plans, including $14 million attributable to Liability Awards that are expected to be settled in cash on their vesting dates. The weighted average remaining vesting period of the awards is less than three years . Restricted stock awards. During 2018 , the Company awarded 503,982 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 113,364 shares or units representing Liability Awards). Restricted stock award activity is as follows: Year Ended December 31, 2018 Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 916,223 $ 151.71 252,735 Shares granted 390,618 $ 180.66 113,364 Shares forfeited (60,103 ) $ 168.20 (26,967 ) Shares vested (447,066 ) $ 150.83 (137,631 ) Outstanding at end of year 799,672 $ 165.10 201,501 The weighted average grant-date fair value of restricted stock Equity Awards awarded during 2018 , 2017 and 2016 was $180.66 , $180.50 and $122.72 , respectively. The grant-date fair value of restricted stock Equity Awards that vested during 2018 , 2017 and 2016 was $67 million , $70 million and $66 million , respectively. As of December 31, 2018 and 2017 , accounts payable - due to affiliates in the consolidated balance sheets includes $14 million and $20 million , respectively, of liabilities attributable to the Liability Awards, representing the fair value of the earned, but unvested, portion of the outstanding awards as of that date. The cash paid for Liability Awards that vested during 2018 , 2017 and 2016 was $24 million , $20 million and $18 million , respectively. Performance unit awards. During 2018 , 2017 and 2016 , the Company awarded performance units to certain of the Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34 -month service period. The grant-date fair values per unit of the 2018 , 2017 and 2016 performance unit awards were $246.18 , $258.27 and $203.69 , respectively, which were determined using the Monte Carlo simulation model, and are being recorded as stock-based compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the performance period of approximately three years . The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. Assumptions used to estimate the fair value of performance unit awards granted are as follows: Year Ended December 31, 2018 2017 2016 Risk-free interest rate 2.41% 1.42% 0.96% Range of volatilities 30.4 % - 53.3% 33.6 % - 58.2% 28.3 % - 53.6% Performance unit activity is as follows: Year Ended December 31, 2018 Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 163,158 $ 223.45 Units granted 62,541 $ 246.18 Units forfeited (1,285 ) $ 225.14 Units vested (b) (105,245 ) $ 204.68 Ending performance unit awards 119,169 $ 251.92 _____________________ (a) Amount reflects the number of performance units initially granted. The actual payout of shares upon vesting may be between zero percent and 250 percent of the performance units included in this table depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. (b) Amount reflects the number of performance units vested upon retirement of eligible officers and the vesting of performance units for which the service period has ended. On December 31, 2018 , the service period lapsed on 103,334 performance unit awards that earned 1.10 shares for each vested award, representing 113,674 aggregate shares of common stock issued on January 2, 2019. The vested performance units that earned 1.10 shares for each vested award included 68,556 units that vested in the current year and 34,778 units that vested in prior years associated with the retirement of the participant. In addition, 1,911 units vested upon retirement of an eligible officer and will be issued when the performance period ends in 2019. The grant-date fair value of performance units that vested during 2018 , 2017 and 2016 was $21 million , $18 million and $15 million , respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
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. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. Asset retirement obligations activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Beginning asset retirement obligations $ 271 $ 297 $ 285 Obligations assumed in acquisitions — — 2 New wells placed on production 1 3 2 Changes in estimates (a) 16 (9 ) 17 Dispositions (89 ) (7 ) — Liabilities settled (30 ) (32 ) (27 ) Accretion of discount 14 19 18 Ending asset retirement obligations $ 183 $ 271 $ 297 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The increase in 2018 is primarily due to an increase in abandonment expense estimates, offset by an increase in commodity prices, which has the effect of lengthening the economic life of the Company's producing wells. Abandonment expense estimates used in the calculation of asset retirement obligations are based on actual cost incurred per well for such costs. The decrease in 2017 was primarily due to an increase in commodity prices, which has the effect of lengthening the economic life of the Company's producing wells. The Company classifies the current and noncurrent portions of asset retirement obligations as other current liabilities and other liabilities, respectively, in the consolidated balance sheets. As of December 31, 2018 and 2017 , the current portion of the Company's asset retirement obligations were $25 million and $41 million , respectively.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $30 million . Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation. Legal actions. The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Environmental. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement or remediation occurs. 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 that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations. Also associated with our divestiture transactions, the Company has issued and received guarantees to facilitate the transfer of contractual obligations such as firm transportation agreements or gathering and processing arrangements. The Company believes the likelihood of making or receiving payments under these guarantees to be remote. As of December 31, 2018 the maximum amount of payments the Company could be required to make under the guarantees is $132 million , which could be partially offset by credit support from third parties of $69 million . Texas Commission on Environmental Quality ("TCEQ") enforcement action. The Company has been advised by the TCEQ that the agency is pursuing an enforcement action against the Company and may seek monetary sanctions due to various emissions occurring during the Company's ownership of the Fain gas plant in the West Panhandle region of Texas, which was sold during 2018. The Company has engaged in discussions with the TCEQ regarding these matters and the TCEQ staff has proposed an enforcement order that is acceptable to, and has been executed by, the Company. The proposed enforcement order is now awaiting formal consideration and approval by TCEQ commissioners. Commissioner approval is not assured and the Company cannot predict the outcome of the TCEQ commissioner considerations with any certainty. The Company believes such monetary sanctions will not exceed $235,500 in the aggregate. Lease commitments. The Company leases drilling rigs, storage tanks, equipment and office facilities under operating leases. Rent expense for the years ended December 31, 2018 , 2017 and 2016 was $98 million , $82 million and $69 million , respectively. In June 2017, the Company entered into a 20 -year operating lease for the Company's new corporate headquarters that is currently being constructed in Irving, Texas. Annual base rent is expected to be $33 million and lease payments are expected to commence once the building is complete, which is expected to occur during the second half of 2019. The Company has a variable equity interest in the entity that is constructing the building. The Company is not the primary beneficiary of the variable interest entity and only has a profit sharing interest after certain economic returns are achieved. The Company has no exposure to the variable interest entity's losses or future liabilities, if any. The Company is the deemed owner of the building (for accounting purposes) during the construction period and is following the build-to-suit accounting guidance. The build-to-suit asset and liability associated with the Company's new corporate headquarters are as follows: As of December 31, 2018 2017 (in millions) Other property and equipment, net (a) $ 217 $ 57 Other noncurrent liabilities (b) $ 219 $ 56 ____________________ (a) A noncash investing activity for purposes of the consolidated statements of cash flows. (b) A noncash financing activity for purposes of the consolidated statements of cash flows. Drilling commitments. The Company's principal drilling commitments are related to drilling rig contracts that require the Company to pay day rates for contracted drilling rigs over their contractual term. The majority of the drilling rig day rates are linked to oil prices causing the day rates to fluctuate over the contract term as oil prices change. In addition, the Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company recognizes its drilling commitments in the periods in which the rig services are performed. Firm commitments. The Company from time to time enters into, and is a party to, take-or-pay agreements, which include contractual commitments to purchase sand and water for use in the Company's drilling operations and contractual commitments with midstream service companies and pipeline carriers for future gathering, processing, transportation, fractionation and storage. These commitments are normal and customary for the Company's business activities. Certain future minimum gathering, processing, transportation, fractionation and storage fees are based upon rates and tariffs that are subject to change over the terms of the commitments. Minimum commitments are as follows: As of December 31, 2018 Lease Commitments Firm Commitments Total (in millions) 2019 $ 234 $ 662 $ 896 2020 169 694 863 2021 97 690 787 2022 66 546 612 2023 40 323 363 Thereafter 647 1,516 2,163 Total minimum commitments $ 1,253 $ 4,431 $ 5,684 Gas delivery commitments. The Company has contracts that require delivery of fixed volumes of gas. The Company intends to fulfill its short-term and long-term obligations with production or from purchases of third party volumes. Delivery commitments for gas are as follows: As of December 31, 2018 (MMBtu per day) 2019 38,247 2020 111,557 2021 100,000 2022 100,000 2023 100,000 2024 83,675

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions On December 31, 2018 , the Company completed the sale of its pressure pumping assets to ProPetro in exchange for 16.6 million shares of ProPetro common stock and $110 million of short-term receivables to be paid by ProPetro during the first quarter of 2019. The shares acquired in the acquisition represent approximately 16 percent of ProPetro's outstanding common stock, resulting in ProPetro being considered a related party as of December 31, 2018 . In addition to the sale of equipment and related facilities, the Company entered into a long-term agreement with ProPetro to provide pressure pumping and related services. See Note 2 and Note 3 for additional information. In February 2019, the Company exercised its right to designate (i) a director to the board of directors of ProPetro, which right will exist for so long as the Company owns five percent or more of ProPetro’s outstanding common stock, and (ii) an independent director to the board of directors of ProPetro, which is a one time right. Mark S. Berg, the Company’s Executive Vice President Corporate/Vertically Integrated Operations, was the Company’s designee in the first category, and Royce W. Mitchell, an independent member of the Company’s board of directors, was the Company’s designee in the second category. Balances with the Company's affiliate are as follows: As of December 31, 2018 (in millions) Accounts receivable - due from affiliate (a) $ 119 Accounts payable - due to affiliate (b) $ 37 ____________________ (a) Includes $110 million of short-term receivables and employee-related charges to be reimbursed by ProPetro. (b) Prior to the Company's sale of its pressure pumping assets to ProPetro, the Company utilized the services of ProPetro in the normal course of business. The balance represents invoices associated with those services that are in the process of being paid.

Major Customer

Major Customer	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Major Customers	Major Customers Purchasers of the Company's oil, NGL and gas production that individually accounted for ten percent or more of the Company's oil and gas revenues in at least one of the three years ended December 31, 2018 are as follows: Year Ended December 31, 2018 2017 2016 Sunoco Logistics Partners L.P. 28 % 21 % 19 % Occidental Energy Marketing Inc. 17 % 16 % 16 % Plains Marketing L.P. 15 % 14 % 16 % Enterprise Products Partners L.P. 6 % 11 % 12 % The loss of any of these major purchasers of oil, NGL and gas production could have a material adverse effect on the ability of the Company to produce and sell its oil, NGL and gas production. Purchasers of the Company's purchased oil and gas that individually accounted for ten percent or more of the Company's sales of purchased oil and gas in at least one of the three years ended December 31, 2018 are as follows: Year Ended December 31, 2018 2017 2016 Occidental Energy Marketing Inc. 34 % 39 % 27 % Valero Marketing and Supply Company 9 % 14 % 17 % BP Energy 9 % 11 % 18 % Exxon Mobil 5 % 11 % 23 % The loss of any of these major purchasers of purchased oil and gas would not be expected to have an adverse effect on the ability of the Company to sell commodities it purchases from third parties.

Revenue Recognition (Notes)

Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2018
Revenue Recognition [Abstract]
Revenue Recognition	Revenue Recognition The Company recognizes revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. See Note 2 for additional information. Disaggregated revenue from contracts with purchasers. Revenues on sales of oil, NGL, gas and purchased oil and gas are recognized when control of the product is transferred to the purchaser and payment can be reasonably assured. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, distance from the well to the pipeline or market, commodity quality and prevailing supply and demand conditions. As such, the prices of oil, NGL and gas generally fluctuate based on the relevant market index rates. Disaggregated revenue from contracts with purchasers by product type is as follows: Year Ended December 31, 2018 (in millions) Oil sales $ 3,991 NGL sales 695 Gas sales 305 Total oil and gas sales 4,991 Sales of purchased oil 4,339 Sales of purchased gas 49 Total sales of purchased oil and gas 4,388 $ 9,379 Oil sales . Sales under the Company's oil contracts are generally considered performed when the Company sells oil production at the wellhead and receives an agreed-upon index price, net of any price differentials. The Company recognizes revenue when control transfers to the purchaser at the wellhead based on the net price received. NGL and gas sales . The Company evaluated whether it was the principal or the agent in gas processing transactions and concluded that it is the principal when it has the ability to take-in-kind, which is the case in the majority of the Company's gas processing and transportation contracts. Therefore, beginning January 1, 2018, the Company began recognizing revenue on a gross basis, with the gathering, processing and transportation costs associated with its take-in-kind arrangements being recorded as oil and gas production costs in the consolidated statement of operations. Gas and NGL processing fees that were previously reflected as a reduction in the Company's reported gas and NGL revenue are now recorded as an expense in the Company's production costs. Sales of purchased oil and gas . The Company enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production. The Company also enters into purchase transactions with third parties and separate sale transactions with third parties to (i) diversify a portion of the Company's oil sales to the Gulf Coast refinery or international export markets and (ii) satisfy unused gas pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The transportation costs associated with these transactions are presented as a component of purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are recorded as other expense in the consolidated statements of operations. Performance obligations and contract balances. The majority of the Company's product sale commitments are short-term in nature with a contract term of one year or less. The Company typically satisfies its performance obligations upon transfer of control as described above in Disaggregated revenue from contracts with purchasers and records the related revenue in the month production is delivered to the purchaser. Settlement statements for sales of oil, NGL and gas and sales of purchased oil and gas may not be received for 30 to 60 days after the date the volumes are delivered, and as a result, the Company is required to estimate the amount of volumes delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The implementation of ASC 606 has not changed existing controls around revenue estimates and the accrual process. Historically, differences between the Company's revenue estimates and actual revenue received have not been significant. As of December 31, 2018 and 2017 , the accounts receivable balance representing amounts due or billable under the terms of contracts with purchasers was $646 million and $594 million , respectively.

Interest And Other Income

Interest And Other Income	12 Months Ended
	Dec. 31, 2018
Other Income and Expenses [Abstract]
Interest and Other Income	Interest and Other Income The components of interest and other income are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Interest income $ 29 $ 32 $ 22 Seismic data sales 5 — — Severance, sales and property tax refunds 1 13 2 Deferred compensation plan income (loss) (2 ) 4 3 Right of way income 4 1 — Other income 1 3 5 $ 38 $ 53 $ 32

Other Expense

Other Expense	12 Months Ended
	Dec. 31, 2018
Other Income and Expenses [Abstract]
Other Expense	Other Expense The components of other expense are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Accelerated depreciation (a) $ 443 $ — $ — Asset divestiture-related charges (b) 173 — 4 Transportation commitment charges (c) 161 167 109 Legal and environmental charges 19 20 6 Loss (income) from vertical integration services (d) 2 17 54 Idle drilling and well service equipment charges (e) — — 64 Other 51 40 51 $ 849 $ 244 $ 288 ____________________ (a) Represents accelerated depreciation related to the decommissioning of the Company's Brady, Texas sand mine. See Note 3 for additional information. (b) Primarily represents $111 million of deficiency charges related to certain firm transportation contracts retained by the Company associated with the sale of its gas field assets in the Raton Basin, $39 million of employee-related charges associated with the Company's 2018 divestitures and sand mine decommissioning efforts and $13 million of contract termination charges associated with the sale of the Company's pressure pumping assets. See Note 3 for additional information. (c) Primarily represents firm transportation charges on excess pipeline capacity commitments. (d) Primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2018 , 2017 and 2016 , these vertical integration net margins included $128 million , $140 million and $147 million of gross vertical integration revenues, respectively, and $130 million , $157 million and $201 million of total vertical integration costs and expenses, respectively. (e) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations and charges to terminate rig contracts that were not required to meet planned drilling activities.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company and its eligible subsidiaries file a consolidated U.S. federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated U.S. federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by U.S. federal, state, local and foreign taxing authorities. Taxes paid, net of refunds are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Taxes paid, net of (refunds) $ — $ — $ (66 ) The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and based on that information, along with other data, reassesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the U.S. federal, state, local and foreign tax jurisdictions will be utilized prior to their expiration. Enactment of the Tax Cuts and Jobs Act. On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the "Tax Reform Legislation"), which introduced significant changes to the U.S. federal income tax law. The changes that most impact the Company include: • A reduction in the federal corporate income tax rate from 35 percent to 21 percent . The rate reduction is effective for the Company as of January 1, 2018. The application of the rate change on the Company's existing deferred tax liabilities resulted in a $625 million income tax benefit to the Company during 2017 . • Repeal of the corporate alternative minimum tax ("AMT"). The Tax Reform Legislation provides that existing AMT credit carryovers are refundable beginning in 2018 . As of December 31, 2018 , the Company had AMT credit carryovers of $20 million that are expected to be fully refunded by 2022 . • The Tax Reform Legislation preserves the deductibility of intangible drilling costs and provides for 100 percent bonus depreciation on personal tangible property expenditures through 2022. The bonus depreciation percentage is phased down from 100 percent beginning in 2023 through 2026. The Tax Reform Legislation is a comprehensive bill containing other provisions, such as limitations on the deductibility of interest expense and certain executive compensation, that are not expected to materially affect Pioneer. The ultimate impact of the Tax Reform Legislation may differ from the Company's estimates as of December 31, 2018 due to changes in the interpretations and assumptions made by the Company as well as additional regulatory guidance that may be issued. ASC 740 "Income Taxes" requires companies to recognize the effect of tax law changes in the period of enactment. However, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 118 that allowed companies to record provisional amounts during a measurement period not extending beyond one year from the Tax Reform Legislation enactment date. The Company’s accounting for the impacts of the Tax Reform Legislation is complete as of December 31, 2018 , and the Company has not recorded any material adjustments to the provisional amounts recorded in the fourth quarter of 2017 related to the Tax Reform Legislation. Uncertain tax positions. 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. The Company has unrecognized tax benefits ("UTBs") resulting from research and experimental expenditures related to horizontal drilling and completion innovations. If all or a portion of the UTBs is sustained upon examination by the taxing authorities, the tax benefit will be recorded as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recorded. The timing as to when the Company will substantially resolve the uncertainties associated with the UTBs is uncertain. Unrecognized tax benefit activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Beginning unrecognized tax benefits $ 124 $ 112 $ — Additions based on current year tax positions 17 12 112 Ending unrecognized tax benefits $ 141 $ 124 $ 112 Other tax matters. The Company files income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. As of December 31, 2018 , there are no proposed adjustments in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The earliest open years in the Company's key jurisdictions are as follows: U.S. federal 2012 Various U.S. states 2013 Income tax (provision) benefit is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Current: U.S. federal $ — $ 5 $ 22 U.S. state (2 ) — 2 (2 ) 5 24 Deferred: U.S. federal (258 ) 526 375 U.S. state (16 ) (7 ) 4 (274 ) 519 379 Income tax (provision) benefit $ (276 ) $ 524 $ 403 The effective tax rate for income (loss) is reconciled to the United States federal statutory rate as follows: Year Ended December 31, 2018 2017 2016 (in millions, except percentages) Income (loss) before income taxes $ 1,251 $ 309 $ (959 ) Net loss attributable to noncontrolling interests 3 — — Income (loss) attributable to common stockholders before income taxes $ 1,254 $ 309 $ (959 ) Federal statutory income tax rate 21 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate (263 ) (108 ) 336 State income tax (provision) benefit (net of federal tax) (12 ) (4 ) 3 State valuation allowance (net of federal tax) (2 ) (1 ) (3 ) Change in federal income tax rate (a) — 625 — Equity compensation excess tax benefit 3 9 — Federal credit for increasing research activities (net of UTBs) 6 6 68 State credit for increasing research activities (net of UTBs and federal tax) — — 4 Other (8 ) (3 ) (5 ) Income tax (provision) benefit $ (276 ) $ 524 $ 403 Effective income tax rate, excluding net loss attributable to noncontrolling interests 22 % (170 )% 42 % ____________________ (a) During 2017, the Company recorded a benefit of $625 million as a result of the Tax Reform Legislation that reduced the federal income tax rate beginning in 2018. Significant components of deferred tax assets and deferred tax liabilities are as follows: December 31, 2018 2017 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 882 $ 594 Credit carryforwards (b) 111 87 Asset retirement obligations 40 59 Incentive plans 48 48 Net deferred hedge losses 11 52 Other 51 22 Total deferred tax assets 1,143 862 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (2,248 ) (1,604 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (47 ) (157 ) Total deferred tax liabilities (2,295 ) (1,761 ) Net deferred tax liability $ (1,152 ) $ (899 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2018 consist of $4.2 billion of U.S. federal NOLs, which expire between 2032 and 2038 . Additionally, the net operating loss carryforwards consist of $177 million of Colorado NOLs that begin to expire in 2027 , all of which have a fully offsetting valuation allowance. (b) Credit carryforwards as of December 31, 2018 , consist of $20 million of U.S. federal minimum tax credits. Additionally, the credit carryforwards consist of $88 million of U.S. federal credits and $3 million of Texas credits for increasing research activities. The U.S. federal and state research credits as of December 31, 2018 exclude $141 million of unrecognized tax benefits.

Net Income Per Share Attributab

Net Income Per Share Attributable To Common Stockholders	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Net Income Per Share Attributable To Common Stockholders	Net Income (Loss) Per Share The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. Diluted net income (loss) per share attributable to common stockholders is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The components of basic and diluted net income (loss) per share attributable to common stockholders are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Net income (loss) attributable to common stockholders $ 978 $ 833 $ (556 ) Participating share based earnings (a) (5 ) (6 ) — Basic and diluted net income (loss) attributable to common stockholders $ 973 $ 827 $ (556 ) ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so. Basic and diluted weighted average common shares outstanding were 171 million , 170 million and 166 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Stock repurchase program . In December 2018, the Company's board of directors authorized a common stock repurchase program that will allow the Company to repurchase up to $2 billion of its common stock. Under this stock repurchase program, the Company may repurchase shares from time to time at management's discretion in accordance with applicable securities laws. In addition, the Company may repurchase shares pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Act of 1934, which would permit the Company to repurchase shares at times that may otherwise be prohibited under the Company's insider trading policy. The stock repurchase program has no time limit, may be modified, suspended or terminated at any time by the board of directors and replaces and terminates the Company's prior $100 million common stock repurchase program announced in February 2018. During 2018 , the Company repurchased $22 million of common stock pursuant to the prior common stock repurchase program and $127 million of common stock pursuant to the newly authorized common stock repurchase program. As of December 31, 2018 , $1.9 billion remains available for use to repurchase shares under the newly authorized common stock repurchase program.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events In February 2019, the board of directors declared a cash dividend of $0.32 per share on Pioneer's outstanding common stock, payable April 12, 2019 to stockholders of record at the close of business on March 29, 2019.

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated.
Reclassifications	Certain reclassifications have been made to prior period amounts to conform to the current period's presentation.
Use of estimates in the preparation of financial statements	Use of estimates in the preparation of financial statements. Preparation of the Company's consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.
Cash and cash equivalents	Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.
Investments	Investments. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are classified as short-term investments or long-term investments in the consolidated balance sheets based on their maturity dates
Accounts receivable	Accounts receivable. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers. T he Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. As of December 31, 2018 and 2017 , the Company's allowance for doubtful accounts totaled $2 million and $1 million , respectively. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.
Inventories	Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, water, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations. During the second quarter of 2018, the Company made a voluntary change in accounting policy to account for its materials and supplies inventory on a weighted average cost basis, versus using the previous accounting policy of the first-in-first-out basis. The Company made this voluntary change in accounting policy because it believes this method is preferable, as the weighted average cost basis more closely aligns with the physical flow of material and supplies inventory and is more widely utilized in the oil and gas industry. This voluntary change in accounting policy did not have a material effect on the Company's consolidated financial statements for prior periods. As such, prior periods have not been restated. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, NGLs and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations.
Oil and gas properties	Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note 6 for additional information. The Company owns interests in 11 gas processing plants and two treating facilities. The Company is the operator of the two treating facilities and none of the gas processing plants. Two of the gas processing facilities are under construction and one of the treating facilities is not currently being used. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third-party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third-party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third-party revenues generated from the processing plants and treating facilities for the years ended December 31, 2018 , 2017 and 2016 were $78 million , $60 million and $41 million , respectively. Third-party expenses attributable to the processing plants and treating facilities for the same respective periods were $36 million , $26 million and $24 million . The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note 4 for additional information. Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time.
Goodwill	Goodwill. Goodwill is assessed for impairment whenever it is likely that events or circumstances indicate the carrying value of a reporting unit exceeds its fair value, but no less often than annually. An impairment charge is recorded for the amount by which the carrying amount exceeds the fair value of a reporting unit in the period it is determined to be impaired. In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-04, "Simplifying the Test of Goodwill Impairment" ("ASU 2017-04"). ASU 2017-04 simplifies the quantitative goodwill impairment test by eliminating the requirement to calculate the implied fair value of goodwill (step 2 of the previous goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit's carrying value over its fair value (as measured in step 1 of the previous goodwill impairment test). ASU 2017-04 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. In July 2018, the Company elected to early adopt this update. The adoption of ASU 2017-04 had no impact on the Company's consolidated financial statements. The Company performed its annual qualitative assessment of goodwill during the third quarter of 2018 to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount. Based on the results of the assessment, the Company determined it was not likely that the carrying value of the Company's reporting unit exceeded its fair value.
Other property and equipment, net	Other property and equipment, net. Other property and equipment is recorded at cost. The net carrying values of other property and equipment are as follows: As of December 31, 2018 (a) 2017 (a) (in millions) Land and buildings (b) $ 380 $ 469 Proved and unproved sand properties (c) 36 468 Water infrastructure (d) 343 319 Transport and field equipment (b)(e) 50 152 Information technology 143 140 Leasehold improvements 13 20 Furniture and fixtures 15 19 Construction in progress and capitalized interest (f) 311 175 $ 1,291 $ 1,762 ____________________ (a) At December 31, 2018 and 2017 , other property and equipment was net of accumulated depreciation of $854 million and $937 million , respectively. (b) The decrease from December 31, 2017 is primarily due to the Company's sale of its pressure pumping assets on December 31, 2018 . (c) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. The decrease from December 31, 2017 is primarily due to the Company's plan to close its sand mine located in Brady, Texas. Other property and equipment associated with the Brady, Texas sand mine was subject to accelerated depreciation to reduce such property and equipment to its net realizable value by its expected closure in May 2019. The accelerated depreciation associated with the planned closure is recorded to other expense in the consolidated statements of operations. See Note 3 for additional information. (d) Includes pipeline infrastructure costs and water supply wells. (e) Includes vehicles and well servicing equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, construction equipment and fishing tools that provide well services on Company-operated properties. (f) Includes capitalized costs and capitalized interest on other property and equipment not yet placed in service as of December 31, 2018 and 2017 . Construction in progress, including related capitalized interest, associated with the Company's new corporate headquarters was $217 million and $ 57 million as of December 31, 2018 and 2017 , respectively. See Note 10 for additional information. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years . Equipment, vehicles, furniture and fixtures and information technology assets are generally depreciated over two to 15 years . Water infrastructure is generally depreciated over ten to 50 years . Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method.
Asset retirement obligations	Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the consolidated balance sheets and expenditures are classified as cash used in operating activities in the consolidated statements of cash flows. See Note 9 for additional information.
Treasury stock	Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
Revenue recognition	Revenue recognition. The Company recognizes revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted ASU No. 2014-09, Accounting Standards Codification ("ASC") 606, "Revenue from Contracts with Customers" ("ASC 606"), which supersedes the revenue recognition requirements in ASC 605, "Revenue Recognition" ("ASC 605"), on January 1, 2018 using the modified retrospective transition method. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting under ASC 605. The Company completed a detailed review of its revenue contracts in 2017, which represented all of the Company's revenue streams including oil, NGL and gas sales and sales of purchased oil and gas, in order to adopt the new standard beginning on January 1, 2018. The Company did not record a change to its opening retained earnings as of January 1, 2018 as there was no material change to the timing or pattern of revenue recognition due to the adoption of ASC 606. Prior to the adoption of ASC 606 on January 1, 2018, the Company recognized revenue when it was realized or realizable and earned. Revenues were considered realized or realizable and earned when: (i) persuasive evidence of an arrangement existed, (ii) delivery occurred or services had been rendered, (iii) the seller's price to the buyer was fixed or determinable and (iv) collectability was reasonably assured. The adoption of ASC 606 as of January 1, 2018 impacted the Company's results of operations as follows: Year Ended December 31, 2018 As Reported ASC 605 Effect of Change (in millions) Revenues and other income: Oil and gas $ 4,991 $ 4,784 $ 207 Costs and expenses: Oil and gas production $ 855 $ 648 $ 207 Changes in oil and gas revenues and oil and gas production costs (specifically gathering, processing and transportation costs) are due to the conclusion under the control model in ASC 606 that the third-party processor or transporter is only providing gas processing or transportation services and that the Company remains the principal owner of the commodity until sold to the ultimate purchaser. This is a change from ASC 605 where the Company historically recorded gas processing fees as a reduction of revenue recognized by the Company, as these fees were considered necessary to separate the wet gas stream into its sellable components (i.e., dry gas and individual NGL components). Under ASC 605, third-party processing and transportation companies were determined to have control of the commodities being processed and transported. As a result of adopting ASC 606, the Company has modified its presentation of revenues and expenses for these arrangements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party purchasers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the purchaser, are now presented as oil and gas production costs. See Note 13 for additional information. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate oil ("WTI") sales to a Gulf Coast or export market price and to satisfy unused gas pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. Transportation costs associated with purchases and sales of third-party oil and gas are presented on a net basis in purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are recorded as other expense in the consolidated statements of operations. See Note 15 for additional information.
Derivatives	Derivatives. All of the Company's derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. 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 Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date.
Income taxes	Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date. The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all of the deferred tax assets will not be realized. 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. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. See Note 16 for additional information.
Stock-based compensation	Stock-based compensation. Stock-based compensation expense for restricted stock, restricted stock units and performance units expected to be settled in the Company's common stock ("Equity Awards") is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of estimated forfeitures, on a straight line basis over the vesting period of the respective award. The fair value of Equity Awards, except performance unit awards, is determined on the grant date or modification date, as applicable, using the prior day's closing stock price. The fair value of performance unit awards is determined using the Monte Carlo simulation model. Equity Awards are net settled by withholding shares of the Company's common stock to satisfy income tax withholding payments due upon vesting. Remaining vested shares are remitted to individual employee brokerage accounts. Shares to be delivered upon vesting of Equity Awards are made available from authorized, but unissued shares or shares held as treasury stock. Restricted stock awards expected to be settled in cash on their vesting dates, rather than in common stock ("Liability Awards"), are classified as accounts payable – due to affiliates on the consolidated balance sheets. The fair value of Liability Awards on the grant date is determined using the prior day's closing stock price. Liability Awards are marked to fair value as of each balance sheet date using the closing stock price on the balance sheet date. Changes in the fair value of Liability Awards are recorded as increases or decreases to stock-based compensation expense. Equity Awards and Liability awards participate in dividends during vesting periods and generally vest over three years .
Segments	Segments. Based upon how the Company is organized and managed, the Company has one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.
New accounting pronouncements	New accounting pronouncements. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASC 842"). ASC 842 requires lessees to recognize lease assets and lease liabilities for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This standard will be effective for the Company for interim periods beginning January 1, 2019. ASC 842 should be applied using a modified retrospective approach. The Company will elect to apply transition guidance under ASU 2018-11, "Leases (Topic 842) Targeted Improvements," in which ASC 842 is applied at the adoption date, while the comparative periods will continue to be reported in accordance with historic accounting under ASC 840, "Leases." This standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. Based on its current commitments, the Company will be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements and potentially other arrangements. The Company plans to apply certain practical expedients provided in ASC 842 that, among other things, allow entities to not reassess contracts that commenced prior to adoption and to not recognize right of use assets and lease liabilities related to short-term leases. The adoption of ASC 842 will have a material impact on the Company's consolidated balance sheets, but will not have an impact on the consolidated statements of operations or the consolidated statements of cash flows. In preparation for the adoption of the standard, the Company has developed internal controls applicable to the process used to determine financial information required to be recognized and disclosed. Upon adoption of ASC 842, the Company will recognize lease assets and lease liabilities in the range of $300 million to $350 million each, as of January 1, 2019. The Company will also derecognize $217 million of other property and equipment and $219 million of build-to-suit lease liability costs associated with the construction of the Company's new corporate headquarters as this contract will no longer qualify for capitalization. The contract for the Company's new corporate headquarters will be evaluated under ASC 842 upon lease commencement, which is expected to occur during the second half of 2019.
Net income (loss) per share	The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. Diluted net income (loss) per share attributable to common stockholders is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented.

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of adoption of ASC 606	The adoption of ASC 606 as of January 1, 2018 impacted the Company's results of operations as follows: Year Ended December 31, 2018 As Reported ASC 605 Effect of Change (in millions) Revenues and other income: Oil and gas $ 4,991 $ 4,784 $ 207 Costs and expenses: Oil and gas production $ 855 $ 648 $ 207
Schedule of materials and supplies and commodity inventories	The components of inventories are as follows: As of December 31, 2018 2017 (in millions) Materials and supplies (a) $ 128 $ 134 Commodities 114 78 $ 242 $ 212 ____________________ (a) As of December 31, 2018 and 2017 , the Company's materials and supplies inventories were net of valuation allowances of $5 million and $5 million , respectively.
Schedule of other property and equipment, net	Other property and equipment, net. Other property and equipment is recorded at cost. The net carrying values of other property and equipment are as follows: As of December 31, 2018 (a) 2017 (a) (in millions) Land and buildings (b) $ 380 $ 469 Proved and unproved sand properties (c) 36 468 Water infrastructure (d) 343 319 Transport and field equipment (b)(e) 50 152 Information technology 143 140 Leasehold improvements 13 20 Furniture and fixtures 15 19 Construction in progress and capitalized interest (f) 311 175 $ 1,291 $ 1,762 ____________________ (a) At December 31, 2018 and 2017 , other property and equipment was net of accumulated depreciation of $854 million and $937 million , respectively. (b) The decrease from December 31, 2017 is primarily due to the Company's sale of its pressure pumping assets on December 31, 2018 . (c) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. The decrease from December 31, 2017 is primarily due to the Company's plan to close its sand mine located in Brady, Texas. Other property and equipment associated with the Brady, Texas sand mine was subject to accelerated depreciation to reduce such property and equipment to its net realizable value by its expected closure in May 2019. The accelerated depreciation associated with the planned closure is recorded to other expense in the consolidated statements of operations. See Note 3 for additional information. (d) Includes pipeline infrastructure costs and water supply wells. (e) Includes vehicles and well servicing equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, construction equipment and fishing tools that provide well services on Company-operated properties. (f) Includes capitalized costs and capitalized interest on other property and equipment not yet placed in service as of December 31, 2018 and 2017 . Construction in progress, including related capitalized interest, associated with the Company's new corporate headquarters was $217 million and $ 57 million as of December 31, 2018 and 2017 , respectively. See Note 10 for additional information.

Acquisitions and Divestitures A

Acquisitions and Divestitures Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Schedule Allocation of the Acquisition Price	The allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date (in millions) is as follows: Assets acquired: Proved properties $ 79 Unproved properties 347 Other property and equipment 5 Liabilities assumed: Asset retirement obligations (2 ) Other liabilities (1 ) Net assets acquired $ 428
Schedule of Divestiture-related Charges	Divestiture-related and decommissioning-related obligations activity is as follows: Year Ended December 31, 2018 (in millions) Employee-related charges: Beginning employee-related obligations $ — Additions 39 Cash payments (12 ) Ending employee-related obligations 27 Contract termination charges: Beginning contract termination obligations — Additions 124 Cash payments (13 ) Ending contract termination obligations (a) 111 Total divestiture-related and decommissioning-related obligations $ 138 ______________________ (a) Includes $98 million of deficiency charges related to certain firm transportation contracts associated with the divestiture of the Company's gas field assets in the Raton Basin. These obligations were retained by the Company and are expected to be paid as follows: $42 million in 2019 , $44 million in 2020 and $12 million in 2021 .

Disclosures About Fair Value _2

Disclosures About Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Assets and liabilities that are measured at fair value	Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis are as follows: Fair Value Measurements at December 31, 2018 Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value as of December 31, 2018 (in millions) Assets: Commodity derivatives $ — $ 52 $ — $ 52 Deferred compensation plan assets 82 — — 82 Investment in affiliate — 172 — 172 Total assets 82 224 — 306 Liabilities: Commodity derivatives — 27 — 27 Total liabilities — 27 — 27 Total recurring fair value measurements $ 82 $ 197 $ — $ 279 Fair Value Measurements at December 31, 2017 Using Quoted Prices in Significant Other Significant Fair Value as of December 31, 2017 (in millions) Assets: Commodity derivatives $ — $ 11 $ — $ 11 Deferred compensation plan assets 95 — — 95 Total assets 95 11 — 106 Liabilities: Commodity derivatives — 255 — 255 Total liabilities — 255 — 255 Total recurring fair value measurements $ 95 $ (244 ) $ — $ (149 )
Fair value and fair value adjustments, nonrecurring	The fair value and fair value adjustments for proved properties, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks are as follows: Fair Value Fair Value Adjustment Management's Price Outlooks Oil Gas (in millions) Raton Basin March 2017 $ 186 $ (285 ) $ 53.65 $ 3.00 West Panhandle March 2016 $ 33 $ (32 ) $ 49.77 $ 3.24
Carrying values and fair values of financial instruments not carried at fair value	Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets are as follows: December 31, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (in millions) Assets: Cash and cash equivalents: Cash (a) $ 775 775 $ 846 $ 846 Time deposits (a) 50 50 50 50 Total $ 825 $ 825 $ 896 $ 896 Short-term investments: Commercial paper (b) $ 53 53 $ 124 124 Corporate bonds (c) 290 288 642 640 Time deposits (b) 100 100 447 447 Total $ 443 $ 441 $ 1,213 $ 1,211 Long-term investments: Corporate bonds (c) $ 125 $ 125 $ 66 $ 66 Total $ 125 $ 125 $ 66 $ 66 Liabilities: Current portion of long-term debt (d) $ — $ — $ 449 $ 457 Long-term debt (d) $ 2,284 $ 2,374 $ 2,283 $ 2,479 ______________________ (a) Fair value approximates carrying value due to the short-term nature of the instruments. (b) Fair value is determined using Level 2 inputs. (c) Fair value is determined using Level 1 inputs. (d) Fair value is determined using Level 2 inputs. The Company's senior notes are quoted but not actively traded on major exchanges; therefore, fair value is based on periodic values as quoted on major exchanges.

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of oil derivative contracts volume and weighted average price	Volumes per day associated with outstanding oil derivative contracts as of December 31, 2018 and the weighted average oil prices for those contracts are as follows: 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Brent collar contracts with short puts: Volume per day (Bbl) 15,000 15,000 15,000 15,000 Price per Bbl: Ceiling $ 89.90 $ 89.90 $ 89.90 $ 89.90 Floor $ 75.00 $ 75.00 $ 75.00 $ 75.00 Short put $ 65.00 $ 65.00 $ 65.00 $ 65.00
Gas Volume And Weighted Average Price	Volumes per day associated with outstanding gas derivative contracts as of December 31, 2018 and the weighted average gas prices for those contracts are as follows: 2019 First Second Quarter Third Quarter Fourth Quarter Swap contracts: Volume per day (MMBtu) 102,622 50,000 50,000 16,848 Price per MMBtu $ 3.39 $ 2.94 $ 2.94 $ 2.94 Basis swap contracts: Permian Basin index swap volume per day (MMBtu) (a) 57,378 60,000 60,000 — Price differential ($/MMBtu) $ (1.47 ) $ (1.46 ) $ (1.46 ) $ — Southern California index swap volume per day (MMBtu) (b) 100,000 80,000 80,000 80,000 Price differential ($/MMBtu) $ 0.40 $ 0.31 $ 0.31 $ 0.31 Call option contracts sold: Volume per day (MMBtu) (c) 50,000 — — — Price per MMBtu $ 3.93 $ — $ — $ — ____________________ (a) The referenced basis swap contracts fix the basis differentials between the index price at which the Company sells its Permian Basin gas and the HH price used in swap contracts. (b) The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in Arizona and southern California. (c) The premium associated with selling these call option contracts was utilized to improve the swap contract prices for April through October 2019 swap volumes.
Offsetting asset and liability	The fair value of derivative financial instruments not designated as hedging instruments is as follows: Fair Value of Derivative Instruments as of December 31, 2018 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) Asset Derivatives: Commodity price derivatives Derivatives - current $ 59 $ (7 ) $ 52 $ 52 Liability Derivatives: Commodity price derivatives Derivatives - current $ 34 $ (7 ) $ 27 $ 27 Fair Value of Derivative Instruments as of December 31, 2017 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) Asset Derivatives: Commodity price derivatives Derivatives - current $ 13 $ (2 ) $ 11 Commodity price derivatives Derivatives - noncurrent $ 3 $ (3 ) — $ 11 Liability Derivatives: Commodity price derivatives Derivatives - current $ 234 $ (2 ) $ 232 Commodity price derivatives Derivatives - noncurrent $ 26 $ (3 ) 23 $ 255
Schedule of derivative gains and losses recognized on statement of operations	Gains (losses) recorded on derivative contracts are as follows: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recorded as Earnings on Derivatives Amount of Gain/(Loss) Recorded as Earnings on Derivatives Year Ended December 31, 2018 2017 2016 (in millions) Commodity price derivatives Derivative losses, net $ (292 ) $ (99 ) $ (174 ) Interest rate derivatives Derivative losses, net — (1 ) 13 $ (292 ) $ (100 ) $ (161 )
Schedule of derivative assets or liabilities by counterparty	Net derivative assets (liabilities) by counterparty are as follows: December 31, 2018 Net Assets (Liabilities) (in millions) Macquarie Bank $ (27 ) J Aron & Company 2 Bank of Montreal 2 JP Morgan Chase 2 Societe Generale 46 $ 25

Exploratory Well Costs (Tables)

Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Capitalized exploratory well and project activity	Capitalized exploratory well project activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Beginning capitalized exploratory well costs $ 505 $ 323 $ 306 Additions to exploratory well costs pending the determination of proved reserves 2,585 1,956 1,387 Reclassification due to determination of proved reserves (2,557 ) (1,764 ) (1,369 ) Disposition of assets (1 ) — — Exploratory well costs charged to exploration and abandonment expense (23 ) (10 ) (1 ) Ending capitalized exploratory well costs $ 509 $ 505 $ 323
Capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized	Aging 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 are as follows: As of December 31, 2018 2017 2016 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 509 $ 493 $ 318 More than one year — 12 5 $ 509 $ 505 $ 323 Number of projects with exploratory well costs that have been suspended for a period greater than one year — 7 3

Long-term Debt and Interest E_2

Long-term Debt and Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Components of long-term debt	The components of long-term debt, including the effects of issuance costs and issuance discounts, are as follows: December 31, 2018 2017 (in millions) Outstanding debt principal balances: 6.875% senior notes due 2018 (a) $ — $ 450 7.50% senior notes due 2020 450 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 2,300 2,750 Issuance costs and discounts (16 ) (18 ) Long-term debt 2,284 2,732 Less current portion of long-term debt (a) — 449 Long-term debt $ 2,284 $ 2,283 ______________________________ (a) The 6.875% senior notes, net of $106 thousand of unamortized issuance costs and discounts, are classified as current in the consolidated balance sheet as of December 31, 2017.
Principal maturities of long-term debt	Principal payments scheduled to be made on the Company's long-term debt are as follows (in millions): 2019 $ — 2020 $ 450 2021 $ 500 2022 $ 600 2023 $ — Thereafter $ 750
Interest expense	Interest expense activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Cash payments for interest $ 133 $ 164 $ 196 Amortization of issuance discounts 1 1 9 Amortization of capitalized loan fees 4 4 4 Net changes in accruals (6 ) (9 ) 2 Interest incurred 132 160 211 Less capitalized interest (6 ) (7 ) (4 ) $ 126 $ 153 $ 207

Incentive Plans (Tables)

Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of LTIP shares available for issuance	The number of shares available for grant pursuant to awards under the LTIP is as follows: As of December 31, 2018 Approved and authorized awards 12,600,000 Awards issued under plan (7,746,616 ) Awards available for future grant 4,853,384
Number of ESPP shares available for issuance	The number of shares available for issuance under the ESPP is as follows: As of December 31, 2018 Approved and authorized shares 1,250,000 Shares issued (1,002,433 ) Shares available for future issuance 247,567
Schedule of stock-based compensation expense	tock-based compensation expense and the associated income tax benefit are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Restricted stock - Equity Awards $ 65 $ 60 $ 66 Restricted stock - Liability Awards 17 24 24 Performance unit awards 18 17 21 ESPP 2 2 2 $ 102 $ 103 $ 113 Income tax benefit $ 17 $ 19 $ 34
Schedule of restricted stock award activity	Restricted stock award activity is as follows: Year Ended December 31, 2018 Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 916,223 $ 151.71 252,735 Shares granted 390,618 $ 180.66 113,364 Shares forfeited (60,103 ) $ 168.20 (26,967 ) Shares vested (447,066 ) $ 150.83 (137,631 ) Outstanding at end of year 799,672 $ 165.10 201,501
Schedule of assumptions to estimate the fair value	Assumptions used to estimate the fair value of performance unit awards granted are as follows: Year Ended December 31, 2018 2017 2016 Risk-free interest rate 2.41% 1.42% 0.96% Range of volatilities 30.4 % - 53.3% 33.6 % - 58.2% 28.3 % - 53.6%
Schedule of performance unit activity	Performance unit activity is as follows: Year Ended December 31, 2018 Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 163,158 $ 223.45 Units granted 62,541 $ 246.18 Units forfeited (1,285 ) $ 225.14 Units vested (b) (105,245 ) $ 204.68 Ending performance unit awards 119,169 $ 251.92 _____________________ (a) Amount reflects the number of performance units initially granted. The actual payout of shares upon vesting may be between zero percent and 250 percent of the performance units included in this table depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. (b) Amount reflects the number of performance units vested upon retirement of eligible officers and the vesting of performance units for which the service period has ended. On December 31, 2018 , the service period lapsed on 103,334 performance unit awards that earned 1.10 shares for each vested award, representing 113,674 aggregate shares of common stock issued on January 2, 2019. The vested performance units that earned 1.10 shares for each vested award included 68,556 units that vested in the current year and 34,778 units that vested in prior years associated with the retirement of the participant. In addition, 1,911 units vested upon retirement of an eligible officer and will be issued when the performance period ends in 2019.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Schedule of asset retirement obligation activity	Asset retirement obligations activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Beginning asset retirement obligations $ 271 $ 297 $ 285 Obligations assumed in acquisitions — — 2 New wells placed on production 1 3 2 Changes in estimates (a) 16 (9 ) 17 Dispositions (89 ) (7 ) — Liabilities settled (30 ) (32 ) (27 ) Accretion of discount 14 19 18 Ending asset retirement obligations $ 183 $ 271 $ 297 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The increase in 2018 is primarily due to an increase in abandonment expense estimates, offset by an increase in commodity prices, which has the effect of lengthening the economic life of the Company's producing wells. Abandonment expense estimates used in the calculation of asset retirement obligations are based on actual cost incurred per well for such costs. The decrease in 2017 was primarily due to an increase in commodity prices, which has the effect of lengthening the economic life of the Company's producing wells.

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Build-to-suit asset and liability	The build-to-suit asset and liability associated with the Company's new corporate headquarters are as follows: As of December 31, 2018 2017 (in millions) Other property and equipment, net (a) $ 217 $ 57 Other noncurrent liabilities (b) $ 219 $ 56 ____________________ (a) A noncash investing activity for purposes of the consolidated statements of cash flows. (b) A noncash financing activity for purposes of the consolidated statements of cash flows.
Schedule of future minimum drilling commitments	Minimum commitments are as follows: As of December 31, 2018 Lease Commitments Firm Commitments Total (in millions) 2019 $ 234 $ 662 $ 896 2020 169 694 863 2021 97 690 787 2022 66 546 612 2023 40 323 363 Thereafter 647 1,516 2,163 Total minimum commitments $ 1,253 $ 4,431 $ 5,684
Delivery Commitments	Delivery commitments for gas are as follows: As of December 31, 2018 (MMBtu per day) 2019 38,247 2020 111,557 2021 100,000 2022 100,000 2023 100,000 2024 83,675

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	Balances with the Company's affiliate are as follows: As of December 31, 2018 (in millions) Accounts receivable - due from affiliate (a) $ 119 Accounts payable - due to affiliate (b) $ 37

Major Customers (Tables)

Major Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Schedule of revenue by major customer	Purchasers of the Company's oil, NGL and gas production that individually accounted for ten percent or more of the Company's oil and gas revenues in at least one of the three years ended December 31, 2018 are as follows: Year Ended December 31, 2018 2017 2016 Sunoco Logistics Partners L.P. 28 % 21 % 19 % Occidental Energy Marketing Inc. 17 % 16 % 16 % Plains Marketing L.P. 15 % 14 % 16 % Enterprise Products Partners L.P. 6 % 11 % 12 %
Schedule of sales of purchased oil, NGL and gas revenues	Purchasers of the Company's purchased oil and gas that individually accounted for ten percent or more of the Company's sales of purchased oil and gas in at least one of the three years ended December 31, 2018 are as follows: Year Ended December 31, 2018 2017 2016 Occidental Energy Marketing Inc. 34 % 39 % 27 % Valero Marketing and Supply Company 9 % 14 % 17 % BP Energy 9 % 11 % 18 % Exxon Mobil 5 % 11 % 23 %

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue Recognition [Abstract]
Disaggregation of Revenue	Disaggregated revenue from contracts with purchasers by product type is as follows: Year Ended December 31, 2018 (in millions) Oil sales $ 3,991 NGL sales 695 Gas sales 305 Total oil and gas sales 4,991 Sales of purchased oil 4,339 Sales of purchased gas 49 Total sales of purchased oil and gas 4,388 $ 9,379

Interest And Other Income (Tabl

Interest And Other Income (Tables)	12 Months Ended
	Dec. 31, 2018
Other Income and Expenses [Abstract]
Interest And Other Income	The components of interest and other income are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Interest income $ 29 $ 32 $ 22 Seismic data sales 5 — — Severance, sales and property tax refunds 1 13 2 Deferred compensation plan income (loss) (2 ) 4 3 Right of way income 4 1 — Other income 1 3 5 $ 38 $ 53 $ 32

Other Expense (Tables)

Other Expense (Tables)	12 Months Ended
	Dec. 31, 2018
Other Income and Expenses [Abstract]
Schedule of components of other expense	The components of other expense are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Accelerated depreciation (a) $ 443 $ — $ — Asset divestiture-related charges (b) 173 — 4 Transportation commitment charges (c) 161 167 109 Legal and environmental charges 19 20 6 Loss (income) from vertical integration services (d) 2 17 54 Idle drilling and well service equipment charges (e) — — 64 Other 51 40 51 $ 849 $ 244 $ 288 ____________________ (a) Represents accelerated depreciation related to the decommissioning of the Company's Brady, Texas sand mine. See Note 3 for additional information. (b) Primarily represents $111 million of deficiency charges related to certain firm transportation contracts retained by the Company associated with the sale of its gas field assets in the Raton Basin, $39 million of employee-related charges associated with the Company's 2018 divestitures and sand mine decommissioning efforts and $13 million of contract termination charges associated with the sale of the Company's pressure pumping assets. See Note 3 for additional information. (c) Primarily represents firm transportation charges on excess pipeline capacity commitments. (d) Primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2018 , 2017 and 2016 , these vertical integration net margins included $128 million , $140 million and $147 million of gross vertical integration revenues, respectively, and $130 million , $157 million and $201 million of total vertical integration costs and expenses, respectively. (e) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations and charges to terminate rig contracts that were not required to meet planned drilling activities.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of taxes paid	Taxes paid, net of refunds are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Taxes paid, net of (refunds) $ — $ — $ (66 )
Schedule of unrecognized tax benefits	Unrecognized tax benefit activity is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Beginning unrecognized tax benefits $ 124 $ 112 $ — Additions based on current year tax positions 17 12 112 Ending unrecognized tax benefits $ 141 $ 124 $ 112
Summary of open tax years	The earliest open years in the Company's key jurisdictions are as follows: U.S. federal 2012 Various U.S. states 2013
Income tax (provision) benefit attributable to continuing operations	Income tax (provision) benefit is as follows: Year Ended December 31, 2018 2017 2016 (in millions) Current: U.S. federal $ — $ 5 $ 22 U.S. state (2 ) — 2 (2 ) 5 24 Deferred: U.S. federal (258 ) 526 375 U.S. state (16 ) (7 ) 4 (274 ) 519 379 Income tax (provision) benefit $ (276 ) $ 524 $ 403
Reconciliation of federal statutory tax rate	The effective tax rate for income (loss) is reconciled to the United States federal statutory rate as follows: Year Ended December 31, 2018 2017 2016 (in millions, except percentages) Income (loss) before income taxes $ 1,251 $ 309 $ (959 ) Net loss attributable to noncontrolling interests 3 — — Income (loss) attributable to common stockholders before income taxes $ 1,254 $ 309 $ (959 ) Federal statutory income tax rate 21 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate (263 ) (108 ) 336 State income tax (provision) benefit (net of federal tax) (12 ) (4 ) 3 State valuation allowance (net of federal tax) (2 ) (1 ) (3 ) Change in federal income tax rate (a) — 625 — Equity compensation excess tax benefit 3 9 — Federal credit for increasing research activities (net of UTBs) 6 6 68 State credit for increasing research activities (net of UTBs and federal tax) — — 4 Other (8 ) (3 ) (5 ) Income tax (provision) benefit $ (276 ) $ 524 $ 403 Effective income tax rate, excluding net loss attributable to noncontrolling interests 22 % (170 )% 42 % ____________________ (a) During 2017, the Company recorded a benefit of $625 million as a result of the Tax Reform Legislation that reduced the federal income tax rate beginning in 2018.
Schedule of deferred tax assets and liabilities	Significant components of deferred tax assets and deferred tax liabilities are as follows: December 31, 2018 2017 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 882 $ 594 Credit carryforwards (b) 111 87 Asset retirement obligations 40 59 Incentive plans 48 48 Net deferred hedge losses 11 52 Other 51 22 Total deferred tax assets 1,143 862 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (2,248 ) (1,604 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (47 ) (157 ) Total deferred tax liabilities (2,295 ) (1,761 ) Net deferred tax liability $ (1,152 ) $ (899 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2018 consist of $4.2 billion of U.S. federal NOLs, which expire between 2032 and 2038 . Additionally, the net operating loss carryforwards consist of $177 million of Colorado NOLs that begin to expire in 2027 , all of which have a fully offsetting valuation allowance. (b) Credit carryforwards as of December 31, 2018 , consist of $20 million of U.S. federal minimum tax credits. Additionally, the credit carryforwards consist of $88 million of U.S. federal credits and $3 million of Texas credits for increasing research activities. The U.S. federal and state research credits as of December 31, 2018 exclude $141 million of unrecognized tax benefits.

Net Income Per Share Attribut_2

Net Income Per Share Attributable To Common Stockholders (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Reconciliation of net income (loss) attributable to common stockholders, basic and diluted	The components of basic and diluted net income (loss) per share attributable to common stockholders are as follows: Year Ended December 31, 2018 2017 2016 (in millions) Net income (loss) attributable to common stockholders $ 978 $ 833 $ (556 ) Participating share based earnings (a) (5 ) (6 ) — Basic and diluted net income (loss) attributable to common stockholders $ 973 $ 827 $ (556 ) ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so.

Summary Of Significant Accoun_4

Summary Of Significant Accounting Policies (Narrative) (Details) shares in Thousands, $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)shares	Mar. 31, 2016USD ($)shares	Dec. 31, 2018USD ($)segment	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)shares	Jan. 01, 2019USD ($)
Summary Of Significant Accounting Policies [Line Items]
Capitalized construction costs			$ 217	$ 57
Allowances for doubtful accounts			$ 2	1
Natural gas processing plants number			11
Treating facilities number			2
Company operated natural gas processing plants			0
Treating Facilities Under Construction			2
Company Operated Treating Facilities			2
Nonoperated treating facilities			1
Revenue			$ 9,379
Issuance of common stock, shares | shares	6,000	13,800			19,838
Proceeds from issuance of common stock, net of issuance costs	$ 937	$ 1,600	$ 0	$ 0	$ 2,534
Stock-based compensation awards general vesting period			3 years	3 years
Reportable operating segments | segment			1
Build-to-suit lease liability			$ 219	$ 56
Minimum | Buildings
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life			20 years
Minimum | Equipment, vehicles, furniture and fixtures and information technology
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life			2 years
Minimum | Water infrastructure
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life			10 years
Maximum | Buildings
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life			39 years
Maximum | Equipment, vehicles, furniture and fixtures and information technology
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life			15 years
Maximum | Water infrastructure
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life			50 years
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Summary Of Significant Accounting Policies [Line Items]
Revenue			$ 78	60	41
Third party expenses, processing plants and treating facilities			$ 36	$ 26	$ 24
ASU 2016-02 | Subsequent event
Summary Of Significant Accounting Policies [Line Items]
Lease assets						$ 300
Lease liability						$ 350

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Schedule of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Materials and supplies inventories	$ 128	$ 134
Commodities	114	78
Inventories	242	212
Net materials and supplies inventories reserves	$ 5	$ 5

Summary of Significant Accoun_6

Summary of Significant Accounting Policies (Schedule of Other Property Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Other property and equipment, net	$ 1,291	$ 1,762
Accumulated depreciation property, plant and equipment, other assets	854	937
Capitalized construction costs	217	57
Land and buildings (b)
Property, Plant and Equipment [Line Items]
Other property and equipment, net	380	469
Proved and unproved sand properties (c)
Property, Plant and Equipment [Line Items]
Other property and equipment, net	36	468
Water infrastructure
Property, Plant and Equipment [Line Items]
Other property and equipment, net	343	319
Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment, net	50	152
Computer Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment, net	143	140
Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment, net	13	20
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment, net	15	19
Construction in Progress and Capitalized Interest [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment, net	$ 311	$ 175

Summary Of Significant Accoun_7

Summary Of Significant Accounting Policies (Schedule of Adoption of ASC 606) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	$ 9,379
Oil and gas
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	4,991	$ 3,518	$ 2,418
Cost of revenue	855	$ 591	$ 581
Oil and gas | ASU 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	4,991
Cost of revenue	855
ASC 605 (Without Adoption of ASC 606) | Oil and gas | ASU 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	4,784
Cost of revenue	648
Effect of Change | Oil and gas | ASU 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	207
Cost of revenue	$ 207

Acquisitions and Divestitures_2

Acquisitions and Divestitures Acquisitions and Divestitures (Acquisitions Narrative) (Details) a in Thousands, $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)aBoe
Business Acquisition [Line Items]
Proceeds from disposition of assets, net of cash sold		$ 469	$ 352	$ 507
Payments for undeveloped acreage		$ 65	136	$ 446
Permian Basin
Business Acquisition [Line Items]
Net acres acquired | a				28
Net production in barrels | Boe				1,400
Payments for acquisition				$ 428
Acquisition related costs				$ 1
Permian Basin | Discount rate | Proved properties
Business Acquisition [Line Items]
Discount rate				0.10
Permian Basin | Discount rate | Asset retirement obligations
Business Acquisition [Line Items]
Discount rate				0.07
Permian Basin
Business Acquisition [Line Items]
Proceeds from disposition of assets, net of cash sold			$ 77
West Panhandle
Business Acquisition [Line Items]
Proceeds from disposition of assets, net of cash sold	$ 170
Employee-related charges	$ 7

Acquisitions and Divestitures (

Acquisitions and Divestitures (Schedule of Allocation of the Acquisition Price) (Details) - Permian Basin $ in Millions	Aug. 31, 2016USD ($)
Assets acquired:
Proved properties	$ 79
Unproved properties	347
Other property and equipment	5
Liabilities assumed:
Asset retirement obligations	(2)
Other liabilities	(1)
Net assets acquired	$ 428

Acquisitions and Divestitures_3

Acquisitions and Divestitures (Divestitures and Decommissioning Activities) (Details) $ in Millions	1 Months Ended							12 Months Ended
	Dec. 31, 2018USD ($)a	Nov. 30, 2018USD ($)	Aug. 31, 2018USD ($)	Jul. 31, 2018USD ($)	Jun. 30, 2018USD ($)	Apr. 30, 2018USD ($)a	Apr. 30, 2017USD ($)aBoe	Dec. 31, 2018USD ($)a	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investment in affiliate	$ 172							$ 172	$ 0
Gain on disposition of assets, net								290	208	$ 2
Proceeds from disposition of assets, net of cash sold								469	352	507
Accelerated depreciation								443	0	0
Impairment of Oil and Gas Properties								(77)	(285)	(32)
Pressure pumping assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration	282							282
Investment in affiliate	172							$ 172
Gain on disposition of assets, net	30
Loss on Contract Termination	13
Employee-related charges	19
Other divestiture-related charges	6
Reduction of carrying value of goodwill	3
Sinor Nest
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposition of assets, net	54
Reduction of carrying value of goodwill	$ 1
Area of Land | a	2,900							2,900
Proceeds from disposition of assets, net of cash sold	$ 105
Sand mine
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Employee-related charges		$ 7
Accelerated depreciation								$ 443
West Panhandle
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposition of assets, net			$ 127
Employee-related charges			7
Reduction of carrying value of goodwill			1
Proceeds from disposition of assets, net of cash sold			$ 170
Raton Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposition of assets, net				$ 2
Employee-related charges				6
Other divestiture-related charges				117
Reduction of carrying value of goodwill				1
Proceeds from disposition of assets, net of cash sold				54
Impairment of Oil and Gas Properties					$ (77)
Contract deficiency				$ 111
West Eagle Ford Shale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposition of assets, net						$ 75
Reduction of carrying value of goodwill						$ 1
Area of Land | a						10,200
Proceeds from disposition of assets, net of cash sold						$ 100
Martin County
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposition of assets, net							$ 194
Reduction of carrying value of goodwill							2
Proceeds from disposition of assets, net of cash sold							$ 264
Acres sold | a							20,500
Net production in barrels | Boe							1,500
Other proved and unproved properties, inventory and other property and equipment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposition of assets, net								$ 1	14	$ 2
Permian Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from disposition of assets, net of cash sold									$ 77

Acquisitions and Divestitures_4

Acquisitions and Divestitures (Schedule of Divestiture-related Charges) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018
Restructuring Reserve [Roll Forward]
Ending employee-related obligations	$ 138
Total divestiture-related and decommissioning-related obligations	138	$ 138
Employee-related charges:
Restructuring Reserve [Roll Forward]
Beginning employee-related obligations	0
Additions	39
Cash payments	(12)
Ending employee-related obligations	27
Total divestiture-related and decommissioning-related obligations	0	27
Contract termination charges:
Restructuring Reserve [Roll Forward]
Beginning employee-related obligations	0
Additions	124
Cash payments	(13)
Ending employee-related obligations	111
Total divestiture-related and decommissioning-related obligations	0	111
Firm transportation contracts
Restructuring Reserve [Roll Forward]
Ending employee-related obligations	98
Total divestiture-related and decommissioning-related obligations	98	98
2,019		42
2,020		$ 44
2,021	$ 12

Disclosures About Fair Value _3

Disclosures About Fair Value Measurements (Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred compensation plan assets	$ 82	$ 95
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	172
Total assets	306	106
Total liabilities	27	255
Total recurring fair value measurements	279	(149)
Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivatives	52	11
Commodity derivatives	27	255
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred compensation plan assets	82	95
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	0
Total assets	82	95
Total liabilities	0	0
Total recurring fair value measurements	82	95
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivatives	0	0
Commodity derivatives	0	0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred compensation plan assets	0	0
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	172
Total assets	224	11
Total liabilities	27	255
Total recurring fair value measurements	197	(244)
Significant Other Observable Inputs (Level 2) | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivatives	52	11
Commodity derivatives	27	255
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred compensation plan assets	0	0
Total assets	0	0
Total liabilities	0	0
Total recurring fair value measurements	0	0
Significant Unobservable Inputs (Level 3) | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivatives	0	0
Commodity derivatives	$ 0	$ 0

Disclosures About Fair Value _4

Disclosures About Fair Value Measurements (Narrative) (Details) $ in Millions	1 Months Ended			12 Months Ended
	Jul. 31, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)Rate	Dec. 31, 2016USD ($)
Discount rate used in impairment calculation | Rate					10.00%
Impairment of oil and gas properties				$ 77	$ 285	$ 32
Alaska
Impairment charge			$ 32
Raton Basin
Impairment of oil and gas properties		$ 77
Contract deficiency	$ 111
Proved properties | Raton Basin
Impairment of oil and gas properties		65
Other property and equipment | Raton Basin
Impairment of oil and gas properties		$ 12
Discount rate
Oil and gas contracts				0.044

Disclosures About Fair Value _5

Disclosures About Fair Value Measurements (Measured On A Nonrecurring Basis) (Details) $ in Millions	1 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)$ / MMBTU$ / bbl	Mar. 31, 2016USD ($)$ / MMBTU$ / bbl	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Adjustment			$ (77)	$ (285)	$ (32)
Raton Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	$ 186
Fair Value Adjustment	$ (285)
Management oil price outlook | $ / bbl	53.65
Management gas price outlook | $ / MMBTU	3
West Panhandle
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value		$ 33
Fair Value Adjustment		$ (32)
Management oil price outlook | $ / bbl		49.77
Management gas price outlook | $ / MMBTU		3.24

Disclosures About Fair Value _6

Disclosures About Fair Value Measurements (Financial Assets and Liabilities Not Carried At Fair Value) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Disclosure Item Amounts [Domain]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Short-term investments	$ 441	$ 1,211
Current portion of long-term debt	0	449
Long-term debt	2,284	2,283
Cash and cash equivalents	825	896	$ 1,118	$ 1,391
Cash and Cash Equivalents, Fair Value Disclosure	825	896
Short-term investments	443	1,213
Long-term investments	125	66
Carrying Value
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Current portion of long-term debt	0	449
Long-term debt	2,284	2,283
Short-term investments	443	1,213
Long-term investments	125	66
Fair Value
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Current portion of long-term debt	0	457
Long-term debt	2,374	2,479
Cash
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Cash and cash equivalents	775	846
Cash and Cash Equivalents, Fair Value Disclosure	775	846
Time Deposits
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Cash and cash equivalents	50	50
Cash and Cash Equivalents, Fair Value Disclosure	50	50
Commercial Paper | Fair Value, Disclosure Item Amounts [Domain]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Short-term investments	53	124
Commercial Paper | Carrying Value
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Short-term investments	53	124
Corporate Bonds | Fair Value, Disclosure Item Amounts [Domain]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Short-term investments	288	640
Long-term investments	125	66
Corporate Bonds | Carrying Value
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Short-term investments	290	642
Long-term investments	125	66
Time Deposits | Fair Value, Disclosure Item Amounts [Domain]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Short-term investments	100	447
Time Deposits | Carrying Value
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Short-term investments	$ 100	$ 447

Disclosures About Fair Value _7

Disclosures About Fair Value Measurements Schedule of Fair Value Measurements (Cash and Cash Equivalents and Investments) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents	$ 825	$ 896	$ 1,118	$ 1,391
Short-term investments	443	1,213
Long-term investments	$ 125	$ 66

Derivative Financial Instrume_3

Derivative Financial Instruments (Oil Derivative Contracts Volume And Weighted Average Price) (Details)	Dec. 31, 2018bbl / d$ / bbl
Brent Collar Contracts With Short Puts for Fourth Quarter of Year One [Member] | Oil contracts
Trading Activity, Gains and Losses, Net [Line Items]
Volume, barrels per day | bbl / d	15,000
Brent Collar Contracts With Short Puts for Fourth Quarter of Year One [Member] | Oil contracts, price per bbl
Trading Activity, Gains and Losses, Net [Line Items]
Ceiling, price per barrel	89.90
Floor, price per barrel	75
Short put, price per barrel	65
Brent Collar Contracts With Short Puts for First Quarter of Year One [Member] | Oil contracts
Trading Activity, Gains and Losses, Net [Line Items]
Volume, barrels per day | bbl / d	15,000
Brent Collar Contracts With Short Puts for First Quarter of Year One [Member] | Oil contracts, price per bbl
Trading Activity, Gains and Losses, Net [Line Items]
Ceiling, price per barrel	89.90
Floor, price per barrel	75
Short put, price per barrel	65
Brent Collar Contracts With Short Puts for Second Quarter of Year One [Member] | Oil contracts
Trading Activity, Gains and Losses, Net [Line Items]
Volume, barrels per day | bbl / d	15,000
Brent Collar Contracts With Short Puts for Second Quarter of Year One [Member] | Oil contracts, price per bbl
Trading Activity, Gains and Losses, Net [Line Items]
Ceiling, price per barrel	89.90
Floor, price per barrel	75
Short put, price per barrel	65
Brent Collar Contracts With Short Puts for Third Quarter of Year One [Member] | Oil contracts
Trading Activity, Gains and Losses, Net [Line Items]
Volume, barrels per day | bbl / d	15,000
Brent Collar Contracts With Short Puts for Third Quarter of Year One [Member] | Oil contracts, price per bbl
Trading Activity, Gains and Losses, Net [Line Items]
Ceiling, price per barrel	89.90
Floor, price per barrel	75
Short put, price per barrel	65

Derivative Financial Instrume_4

Derivative Financial Instruments (Gas Derivative Contracts Volume And Weighted Average Price) (Details)	Dec. 31, 2018MMBTU / d$ / MMBTU
Basis swap contracts for next year Q1 | Gas contracts, in MMBTU | Permian Basin
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	57,378
Basis swap contracts for next year Q1 | Gas contracts, in MMBTU | Southern California
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	100,000
Basis swap contracts for next year Q1 | Gas contracts, price per MMBTU | Permian Basin
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	(1.47)
Basis swap contracts for next year Q1 | Gas contracts, price per MMBTU | Southern California
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	0.40
Basis swap contracts for next year Q2 | Gas contracts, in MMBTU | Permian Basin
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	60,000
Basis swap contracts for next year Q2 | Gas contracts, in MMBTU | Southern California
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	80,000
Basis swap contracts for next year Q2 | Gas contracts, price per MMBTU | Permian Basin
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	(1.46)
Basis swap contracts for next year Q2 | Gas contracts, price per MMBTU | Southern California
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	0.31
Basis swap contracts for next year Q3 | Gas contracts, in MMBTU | Permian Basin
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	60,000
Basis swap contracts for next year Q3 | Gas contracts, in MMBTU | Southern California
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	80,000
Basis swap contracts for next year Q3 | Gas contracts, price per MMBTU | Permian Basin
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	(1.46)
Basis swap contracts for next year Q3 | Gas contracts, price per MMBTU | Southern California
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	0.31
Swap Contracts For First Quarter of Year One [Member] | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	102,622
Swap Contracts For First Quarter of Year One [Member] | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	3.39
Swap contracts for next year Q4 | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	16,848
Swap contracts for next year Q4 | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	2.94
Swap Contracts For Third Quarter of Year One [Member] | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	50,000
Swap Contracts For Third Quarter of Year One [Member] | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	2.94
Swap Contracts For Second Quarter of Year One [Member] | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	50,000
Swap Contracts For Second Quarter of Year One [Member] | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	2.94
Basis swap contracts for next year Q4 | Gas contracts, in MMBTU | Permian Basin
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	0
Basis swap contracts for next year Q4 | Gas contracts, in MMBTU | Southern California
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	80,000
Basis swap contracts for next year Q4 | Gas contracts, price per MMBTU | Permian Basin
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	0
Basis swap contracts for next year Q4 | Gas contracts, price per MMBTU | Southern California
Derivative [Line Items]
Price differential, dollars per barrel | $ / MMBTU	0.31
Call Option Contracts Sold For First Quarter of Year One [Member] | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	50,000
Call Option Contracts Sold For First Quarter of Year One [Member] | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	3.93
Call Option Contracts Sold For Second Quarter of Year One [Domain] | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	0
Call Option Contracts Sold For Second Quarter of Year One [Domain] | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	0
Call Option Contracts Sold For Third Quarter of Year One [Member] | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	0
Call Option Contracts Sold For Third Quarter of Year One [Member] | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	0
Call Option Contracts Sold For Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU
Derivative [Line Items]
Volume, barrels per day | MMBTU / d	0
Call Option Contracts Sold For Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU
Derivative [Line Items]
Price per MMBtu in usd | $ / MMBTU	0

Derivative Financial Instrume_5

Derivative Financial Instruments (Offsetting Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Asset Derivatives:
Net Fair Value Presented in the Consolidated Balance Sheet, current	$ 52	$ 11
Derivative Liability [Abstract]
Net Fair Value Presented in the Consolidated Balance Sheet, current	27	232
Net Fair Value Presented in the Consolidated Balance Sheet, noncurrent	0	23
Derivatives not designated as hedging instruments
Asset Derivatives:
Net Fair Value Presented in the Consolidated Balance Sheet, total	52	11
Derivative Liability [Abstract]
Net Fair Value Presented in the Consolidated Balance Sheet, total	27	255
Derivatives - current | Derivatives not designated as hedging instruments | Commodity price derivatives
Asset Derivatives:
Fair Value	59	13
Gross Amounts Offset in the Consolidated Balance Sheet	(7)	(2)
Net Fair Value Presented in the Consolidated Balance Sheet, current	52	11
Derivative Liability [Abstract]
Fair Value	34	234
Gross Amounts Offset in the Consolidated Balance Sheet	(7)	(2)
Net Fair Value Presented in the Consolidated Balance Sheet, current	$ 27	232
Derivatives - current | Derivatives not designated as hedging instruments | Interest rate derivatives
Asset Derivatives:
Gross Amounts Offset in the Consolidated Balance Sheet		(3)
Net Fair Value Presented in the Consolidated Balance Sheet, current		0
Derivatives - noncurrent | Derivatives not designated as hedging instruments | Commodity price derivatives
Asset Derivatives:
Fair Value		3
Derivative Liability [Abstract]
Fair Value		26
Gross Amounts Offset in the Consolidated Balance Sheet		(3)
Net Fair Value Presented in the Consolidated Balance Sheet, noncurrent		$ 23

Derivative Financial Instrume_6

Derivative Financial Instruments (Derivative Obligations Under Terminated Hedge Arrangements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Amount of Gain/(Loss) Recorded as Earnings on Derivatives	$ (292)	$ (100)	$ (161)
Commodity price derivatives | Derivative losses, net
Derivative [Line Items]
Amount of Gain/(Loss) Recorded as Earnings on Derivatives	(292)	(99)	(174)
Interest rate derivatives | Derivative losses, net
Derivative [Line Items]
Amount of Gain/(Loss) Recorded as Earnings on Derivatives	$ 0	$ (1)	$ 13

Schedule of Derivative Assets a

Schedule of Derivative Assets and Liabilities by Counterparty (Details) $ in Millions	Dec. 31, 2018USD ($)
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Net Assets (Liabilities)	$ 25
Macquarie Bank
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Net Assets (Liabilities)	(27)
BP Corporation North America
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Net Assets (Liabilities)	2
Credit Agricole
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Net Assets (Liabilities)	2
Bank Of Montreal [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Net Assets (Liabilities)	2
Morgan Stanley Capital Group
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Net Assets (Liabilities)	$ 46

Exploratory Well Costs (Capital

Exploratory Well Costs (Capitalized Exploratory Well And Project Activity) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning capitalized exploratory well costs	$ 505	$ 323	$ 306
Additions to exploratory well costs pending the determination of proved reserves	2,585	1,956	1,387
Reclassification due to determination of proved reserves	(2,557)	(1,764)	(1,369)
Disposition of assets	1	0	0
Exploratory well costs charged to exploration and abandonment expense	(23)	(10)	(1)
Ending capitalized exploratory well costs	$ 509	$ 505	$ 323

Exploratory Well Costs (Capit_2

Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Capitalized exploratory well costs that have been suspended:
One year or less	$ 509	$ 493	$ 318
More than one year	0	12	5
Total	$ 509	$ 505	$ 323	$ 306
Number of projects with exploratory well costs that have been suspended for a period greater than one year	0	7	3

Long-term Debt and Interest E_3

Long-term Debt and Interest Expense (Components Of Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	May 01, 2018	Dec. 31, 2017	Mar. 31, 2017
Debt Instrument [Line Items]
Outstanding debt principal balances, gross	$ 2,300,000		$ 2,750,000
Issuance costs and discounts	(16,000)		(18,000)
Long-term debt	2,284,000		2,732,000
Less current portion of long-term debt	0		449,000
Long-term debt	2,284,000		$ 2,283,000
6.65% senior notes due 2017
Debt Instrument [Line Items]
Senior notes, interest rate				6.65%
6.875% senior notes due 2018
Debt Instrument [Line Items]
Senior notes, interest rate		6.875%	6.875%
Outstanding debt principal balances, gross	0		$ 450,000
Issuance costs and discounts			$ (106)
7.50% senior notes due 2020
Debt Instrument [Line Items]
Senior notes, interest rate			7.50%
Outstanding debt principal balances, gross	450,000		$ 450,000
3.45% senior notes due 2021
Debt Instrument [Line Items]
Senior notes, interest rate			3.45%
Outstanding debt principal balances, gross	500,000		$ 500,000
3.95% senior notes due 2022
Debt Instrument [Line Items]
Senior notes, interest rate			3.95%
Outstanding debt principal balances, gross	600,000		$ 600,000
4.45% senior notes due 2026
Debt Instrument [Line Items]
Senior notes, interest rate			4.45%
Outstanding debt principal balances, gross	500,000		$ 500,000
7.20% senior notes due 2028
Debt Instrument [Line Items]
Senior notes, interest rate			7.20%
Outstanding debt principal balances, gross	$ 250,000		$ 250,000

Long-term Debt and Interest E_4

Long-term Debt and Interest Expense (Narrative) (Details)	May 01, 2018USD ($)Rate	Mar. 31, 2017USD ($)Rate	Dec. 31, 2018USD ($)Rate	Dec. 31, 2017USD ($)Rate	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity | $			$ 1,500,000,000
Outstanding borrowings under the Credit Facility | $			0
Repayments of debt | $			$ 450,000,000	$ 485,000,000	$ 455,000,000
Credit Facility
Debt Instrument [Line Items]
Federal fund rate			0.50%
Alternate base rate spread			0.25%
Applicable margin			1.25%
Letters of credit outstanding under the Credit Facility, interest percentage			0.125%
Unused portion, fee percentage			0.15%
Debt instrument covenant description			0.65
Swing Line Loans | Credit Facility
Debt Instrument [Line Items]
Maximum outstanding borrowings under the Credit Facility | $			$ 150,000,000
6.65% senior notes due 2017
Debt Instrument [Line Items]
Senior Notes, interest rate, percentage		6.65%
Repayments of debt | $		$ 485,000,000
6.875% senior notes due 2018
Debt Instrument [Line Items]
Senior Notes, interest rate, percentage	6.875%			6.875%
Repayments of debt | $	$ 450,000,000

Long-term Debt and Interest E_5

Long-term Debt and Interest Expense (Principal Maturities Of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2018USD ($)
Debt Disclosure [Abstract]
2,018	$ 0
2,020	450
2,021	500
Long-term Debt, Maturities, Repayments of Principal in Year Four	600
2,022	0
Thereafter	$ 750

Long-term Debt and Interest E_6

Long-term Debt and Interest Expense (Interest Expenses) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Cash payments for interest	$ 133	$ 164	$ 196
Amortization of issuance discounts	1	1	9
Amortization of capitalized loan fees	4	4	4
Net changes in accruals	(6)	(9)	2
Interest incurred	132	160	211
Less capitalized interest	(6)	(7)	(4)
Total interest expense	$ 126	$ 153	$ 207

Incentive Plans (Narrative) (De

Incentive Plans (Narrative) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesRateshares	Dec. 31, 2017USD ($)$ / shares	Dec. 31, 2016USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ESPP offering period	8 months
Unrecognized share-based compensation expense | $	$ 80
Remaining vesting period	3 years	3 years
Pioneer Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards | shares	12,600,000
ESPP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee stock purchase plan contribution limit	15.00%
Employee stock purchase plan participants purchase price percent	15.00%
Approved and authorized awards | shares	1,250,000
Restricted stock - Liability Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized share-based compensation expense | $	$ 14
Shares granted | shares	113,364
Grant date fair value | $	$ 24	$ 20	$ 18
Amount of liabilities attributable to liability awards included in accounts payable | $	$ 14	$ 20
Restricted stock units, including liability awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted | shares	503,982
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted | shares	390,618
Shares granted (usd per share) | $ / shares	$ 180.66	$ 180.50	$ 122.72
Grant date fair value | $	$ 67	$ 70	$ 66
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining vesting period	34 months
Shares granted | shares	62,541
Shares granted (usd per share) | $ / shares	$ 246.18	$ 258.27	$ 203.69
Grant date fair value | $	$ 21	$ 18	$ 15
Expected volatility period	3 years
401(k) plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants annual salary contributions, percentage	80.00%
Matching contributions percent	200.00%
Limit of employee's contribution of base salary, percent	5.00%
Matching contributions vesting period in years	4
Recognized compensation matching contribution expense | $	$ 36	25	23
Deferred compensation retirement plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Matching contributions percent	100.00%
Matching contributions | $	$ 3	$ 3	$ 3
Deferred compensation retirement plan | Base salary
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants annual salary contributions, percentage	25.00%
Deferred compensation retirement plan | Annual bonus
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants annual salary contributions, percentage	100.00%
Deferred compensation retirement plan | Officer | Base salary
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Limit of employee's contribution of base salary, percent	10.00%
Deferred compensation retirement plan | Key employee | Annual bonus
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Limit of employee's contribution of base salary, percent	8.00%

Incentive Plans (Number Of Shar

Incentive Plans (Number Of Shares Available Under The Company's Long Term Incentive Plan) (Details) - Pioneer Long Term Incentive Plan [Member]	152 Months Ended
	Dec. 31, 2018shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	12,600,000
Awards issued under plan	(7,746,616)
Awards available for future grant	4,853,384

Incentive Plans (Schedule Of Em

Incentive Plans (Schedule Of Employee Stock Purchase Plan) (Details) - ESPP	264 Months Ended
	Dec. 31, 2018shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized shares	1,250,000
Awards issued under plan	(1,002,433)
Shares available for future issuance	247,567

Incentive Plans (Schedule of Co

Incentive Plans (Schedule of Compensation Expense for Each Type of Incentive Award) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 102	$ 103	$ 113
Income tax benefit (provision)	$ (276)	$ 524	$ 403
Restricted stock - Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (usd per share)	$ 180.66	$ 180.50	$ 122.72
Stock-based compensation expense	$ 65	$ 60	$ 66
Grant date fair value	67	70	66
Restricted stock - Liability Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	17	24	24
Grant date fair value	24	20	$ 18
Amount of liabilities attributable to liability awards included in accounts payable	$ 14	$ 20
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (usd per share)	$ 246.18	$ 258.27	$ 203.69
Stock-based compensation expense	$ 18	$ 17	$ 21
Grant date fair value	21	18	15
ESPP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	2	2	2
Compensation Expense For Incentive Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit (provision)	$ 17	$ 19	$ 34

Incentive Plans (Schedule Of Re

Incentive Plans (Schedule Of Restricted Stock Award Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at beginning of year, shares	916,223
Shares granted	390,618
Shares forfeited	(60,103)
Awards vested	(447,066)
Outstanding at end of year, shares	799,672	916,223
Weighted Average Grant- Date Fair Value
Outstanding (usd per share)	$ 165.10	$ 151.71
Shares granted (usd per share)	180.66	$ 180.50	$ 122.72
Shares forfeited (usd per share)	168.20
Shares vested (usd per share)	$ 150.83
Restricted stock - Liability Awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at beginning of year, shares	252,735
Shares granted	113,364
Shares forfeited	(26,967)
Awards vested	(137,631)
Outstanding at end of year, shares	201,501	252,735

Incentive Plans (Schedule Of As

Incentive Plans (Schedule Of Assumptions To Estimate The Fair Value) (Details) - Performance unit awards	12 Months Ended
	Dec. 31, 2018Rate	Dec. 31, 2017Rate	Dec. 31, 2016Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	2.41%	1.42%	0.96%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	30.40%	33.60%	28.30%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	53.30%	58.20%	53.60%

Incentive Plans (Schedule Of Pe

Incentive Plans (Schedule Of Performance Unit Activity) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Weighted Average Grant- Date Fair Value
Common stock, shares issued	174,321,171	173,796,743
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at beginning of year, shares	163,158
Units granted	62,541
Units forfeited	(1,285)
Units vested	(105,245)
Outstanding at end of year, shares	119,169	163,158
Weighted Average Grant- Date Fair Value
Outstanding (usd per share)	$ 251.92	$ 223.45
Units granted (usd per share)	246.18	$ 258.27	$ 203.69
Units forfeited (usd per share)	225.14
Units vested (usd per share)	$ 204.68
Grant date fair value	$ 21	$ 18	$ 15
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units vested	(68,556)	(34,778)
Weighted Average Grant- Date Fair Value
Performance percentage of actual payout minimum	0.00%
Performance percentage to reach maximum	250.00%
Number of shares earned for each vested award	1.10
Common stock, shares issued	113,674
Performance Units Service Period Lapsed [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units vested	(103,334)
Officer | Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units vested	(1,911)

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 271	$ 297	$ 285
Obligations assumed in acquisitions	0	0	2
New wells placed on production	1	3	2
Changes in estimates (a)	16	(9)	17
Dispositions	(89)	(7)	0
Liabilities settled	(30)	(32)	(27)
Accretion of discount	14	19	18
Ending asset retirement obligations	183	271	$ 297
Asset retirement obligations, current portion	$ 25	$ 41

Commitments And Contingencies_2

Commitments And Contingencies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Current annual salaries of officers and key employees	$ 30,000,000
Loss Contingencies [Line Items]
Maximum guarantee exposure	132,000,000
Guarantor Obligations, Liquidation Proceeds, Monetary Amount	69,000,000
Rent expense	98,000,000	$ 82,000,000	$ 69,000,000
Operating lease term				20 years
Annual base rent	33,000,000
Capitalized construction costs	217,000,000	57,000,000
Build-to-suit lease liability	219,000,000	$ 56,000,000
Unfavorable Regulatory Action [Member] | Maximum
Loss Contingencies [Line Items]
Monetary sanctions	$ 235,500

Commitments And Contingencies C

Commitments And Contingencies Commitments and Contingencies (Schedule of Minimum Commitments) (Details) $ in Millions	Dec. 31, 2018USD ($)
Lease Commitments
2,019	$ 234
2,020	169
2,021	97
2,022	66
2,023	40
Thereafter	647
Total minimum commitments	1,253
Firm Commitments
2,018	662
2,019	694
2,020	690
2,021	546
2,022	323
Thereafter	1,516
Total minimum commitments	4,431
2,019	896
2,020	863
2,021	787
2,022	612
2,023	363
Thereafter	2,163
Total minimum commitments	$ 5,684

Commitments And Contingencies_3

Commitments And Contingencies (Schedule of Delivery Commitments) (Details)	Dec. 31, 2018MMBTU / d
Commitments and Contingencies Disclosure [Abstract]
2,019	38,247
2,020	111,557
2,021	100,000
2,022	100,000
2,023	100,000
2,024	83,675

Commitments And Contingencies_4

Commitments And Contingencies (Build-to-suit Asset and Liability) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Other property and equipment, net	$ 217	$ 57
Other noncurrent liabilities	$ 219	$ 56

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) shares in Millions, $ in Millions	1 Months Ended
	Dec. 31, 2018USD ($)shares
Related Party Transaction [Line Items]
Accounts receivable - due from affiliate	$ 119
Accounts payable - due to affiliate	$ 37
ProPetro
Related Party Transaction [Line Items]
Shares acquired	16.00%
Director designation ownership percent	5.00%
Pressure pumping assets | ProPetro | Sale assets
Related Party Transaction [Line Items]
Shares received | shares	16.6
Short-term receivables	$ 110

Major Customers (Consolidated O

Major Customers (Consolidated Oil, NGL And Gas Revenues) (Details) - Oil, NGL and gas production revenues - Customer concentration	12 Months Ended
	Dec. 31, 2018Rate	Dec. 31, 2017Rate	Dec. 31, 2016Rate
Sunoco Logistics Partners L.P.
Concentration Risk [Line Items]
Concentration risk percent	28.00%	21.00%	19.00%
Occidental Energy Marketing Inc.
Concentration Risk [Line Items]
Concentration risk percent	17.00%	16.00%	16.00%
Plains Marketing L.P.
Concentration Risk [Line Items]
Concentration risk percent	15.00%	14.00%	16.00%
Enterprise Products Partners L.P.
Concentration Risk [Line Items]
Concentration risk percent	6.00%	11.00%	12.00%

Major Customers Major Customers

Major Customers Major Customers (Sales of Purchased Oil and Gas (Details) - Sales of Purchased Oil and Gas [Member]	12 Months Ended
	Dec. 31, 2018Rate	Dec. 31, 2017Rate	Dec. 31, 2016Rate
Occidental Energy Marketing Inc.
Concentration Risk [Line Items]
Concentration risk percent	34.00%	39.00%	27.00%
Valero Marketing and Supply Company
Concentration Risk [Line Items]
Concentration risk percent	9.00%	14.00%	17.00%
BP Energy
Concentration Risk [Line Items]
Concentration risk percent	9.00%	11.00%	18.00%
Exxon Mobil
Concentration Risk [Line Items]
Concentration risk percent	5.00%	11.00%	23.00%

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue	$ 9,379
Accounts receivable, due or billable	646	$ 594
Oil sales
Disaggregation of Revenue [Line Items]
Revenue	3,991
NGL Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue	695
Gas Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue	305
Total Oil and Gas Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue	4,991
Sale of Oil Purchased [Member]
Disaggregation of Revenue [Line Items]
Revenue	4,339
Sale of Gas Purchased [Member]
Disaggregation of Revenue [Line Items]
Revenue	49
Sales of Purchased Oil and Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue	$ 4,388

Interest And Other Income (Inte

Interest And Other Income (Interest And Other Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Income and Expenses [Abstract]
Interest income	$ 29	$ 32	$ 22
Seismic Data Sales	5	0	0
Tax refunds	1	13	2
Deferred compensation plan income (loss)	(2)	4	3
Right of way income	4	1	0
Other income	1	3	5
Interest and other	$ 38	$ 53	$ 32

Other Expense (Details)

Other Expense (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Income and Expenses [Abstract]
Accelerated depreciation		$ 443	$ 0	$ 0
Asset divestiture-related charges		173	0	4
Transportation commitment charges		161	167	109
Legal and environmental charges		19	20	6
Loss (income) from vertical integration services		2	17	54
Idle drilling and well service equipment charges		0	0	64
Other		51	40	51
Total other expense		849	244	288
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross vertical integration revenues		128	140	147
Total vertical integration costs and expenses		130	$ 157	$ 201
Sand mine
Other Income and Expenses [Abstract]
Accelerated depreciation		443
Raton Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contract deficiency	$ 111
Employee-related charges
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Employee related charges		$ 39

Income Taxes (Income Taxes Paid

Income Taxes (Income Taxes Paid) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes Paid [Abstract]
Payments for income taxes, net of tax refunds received	$ 0	$ 0	$ (66)

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Payments for income taxes, net of tax refunds received	$ 0	$ 0	$ (66)
Income tax benefit from from rate change		625
AMT credit carryovers	20
Unrecognized tax benefits	$ 141	$ 124	$ 112	$ 0

Income Taxes (Schedule of Unrec

Income Taxes (Schedule of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning unrecognized tax benefits	$ 124	$ 112	$ 0
Additions based on current year tax positions	17	12	112
Ending unrecognized tax benefits	$ 141	$ 124	$ 112

Income Taxes (Summary Of Open T

Income Taxes (Summary Of Open Tax Years, By Jurisdiction) (Details)	12 Months Ended
	Dec. 31, 2018
U.S. federal
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,012
Various U.S. states
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2,013

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax (Provision) Benefit Allocation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income tax benefit from continuing operations	$ (276)	$ 524	$ 403

Income Taxes (Income Tax (Provi

Income Taxes (Income Tax (Provision) Benefit Attributable To Income From Continuing Operations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
U.S. federal	$ 0	$ 5	$ 22
U.S. state	(2)	0	2
Current income tax (provision) benefit	(2)	5	24
Deferred:
U.S. federal	(258)	526	375
U.S. state	(16)	(7)	4
Deferred income tax benefit	(274)	519	379
Income tax (provision) benefit	$ (276)	$ 524	$ 403

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ 1,251	$ 309	$ (959)
Net loss attributable to noncontrolling interests	(3)	0	0
Income (loss) attributable to common stockholders before income taxes	$ 1,254	$ 309	$ (959)
Federal statutory income tax rate	21.00%	35.00%	35.00%
(Provision) benefit for federal income taxes at the statutory rate	$ (263)	$ (108)	$ 336
State income tax (provision) benefit (net of federal tax)	(12)	(4)	3
State valuation allowance (net of federal tax)	(2)	(1)	(3)
Change in federal income tax rate	0	625	0
Equity compensation excess tax benefit	3	9	0
Federal credit for increasing research activities (net of UTBs)	6	6	68
State credit for increasing research activities (net of UTBs and federal tax)	0	0	4
Other	(8)	(3)	(5)
Income tax (provision) benefit	$ (276)	$ 524	$ 403
Effective income tax rate, excluding net loss attributable to noncontrolling interests	22.00%	(170.00%)	42.00%
Income tax benefit from from rate change		$ 625

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Deferred Tax Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation Allowance [Line Items]
Net operating loss carryforward	$ 882	$ 594
Deferred Tax Assets, Tax Credit Carryforwards, Research	111	87
Asset retirement obligations	40	59
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	48	48
Deferred Tax Assets, Hedging Transactions	11	52
Other	51	22
Total deferred tax assets	1,143	862
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes	(2,248)	(1,604)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes	(47)	(157)
Total deferred tax liabilities	(2,295)	(1,761)
Net deferred tax liability	1,152	899
Unrecognized tax benefits	141	$ 124	$ 112	$ 0
U.S. Federal Tax Credit Carryforward [Member] | U.S.
Valuation Allowance [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Research	20
Research Tax Credit Carryforward [Member] | U.S.
Valuation Allowance [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Research	88
Research Tax Credit Carryforward [Member] | Texas
Valuation Allowance [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Research	3
Domestic Tax Authority [Member]
Valuation Allowance [Line Items]
Net operating loss carryforward	4,200
COLORADO
Valuation Allowance [Line Items]
Net operating loss carryforward	$ 177

Net Income Per Share Attribut_3

Net Income Per Share Attributable To Common Stockholders (Scheule of Net Income (Loss) Reconcilation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement Operating Activities Segment [Line Items]
Net income (loss) attributable to common stockholders	$ 978	$ 833	$ (556)
Participating basic earnings	(5)	(6)	0
Net income (loss) attributable to common stockholders	$ 973	$ 827	$ (556)

Net Income Per Share Attribut_4

Net Income Per Share Attributable To Common Stockholders (Narrative) (Details) - USD ($) shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 13, 2018	Feb. 28, 2018
Equity, Class of Treasury Stock [Line Items]
Basic and diluted weighted average common shares outstanding	171	170	166
Repurchase of common stock	$ 179,000,000	$ 36,000,000	$ 25,000,000
Stock repurchase program
Equity, Class of Treasury Stock [Line Items]
Authorized repurchase amount				$ 2,000,000,000
Repurchase of common stock	127,000,000
Stock Repurchase Program, Remaining Authorized Repurchase Amount	1,900,000,000
Terminated Stock Repurchase Program
Equity, Class of Treasury Stock [Line Items]
Terminated Stock Repurchase Program - Authorized Amount					$ 100,000,000
Repurchase of common stock	$ 22,000,000

Subsequent Events (Details)

Subsequent Events (Details) - $ / shares	1 Months Ended	12 Months Ended
	Feb. 22, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsequent Event [Line Items]
Dividends declared (usd per share)		$ 0.32	$ 0.08	$ 0.08
Future Year Semiannual Amount [Member] | Subsequent event
Subsequent Event [Line Items]
Dividends declared (usd per share)	$ 0.32