Diamondback Energy (FANG) 10-Q 10 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 03, 2019
Document and Entity Information [Abstract]
Document type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Registrant Name	Diamondback Energy, Inc.
Entity Central Index Key	0001539838
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		164,672,205

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 126	$ 215
Accounts receivable:
Joint interest and other, net	107	96
Oil and natural gas sales	356	296
Inventories	39	37
Derivative instruments	5	231
Prepaid expenses and other	60	50
Total current assets	693	925
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($9,646 million and $9,670 million excluded from amortization at March 31, 2019 and December 31, 2018, respectively)	23,229	22,299
Midstream assets	762	700
Other property, equipment and land	151	147
Accumulated depletion, depreciation, amortization and impairment	(3,095)	(2,774)
Net property and equipment	21,047	20,372
Equity method investments	150	1
Deferred tax asset	150	97
Investment in real estate, net	114	116
Other assets	114	85
Total assets	22,268	21,596
Current liabilities:
Accounts payable-trade	180	128
Accrued capital expenditures	485	495
Other accrued liabilities	238	253
Revenues and royalties payable	151	143
Derivative instruments	58	0
Total current liabilities	1,112	1,019
Long-term debt	4,670	4,464
Derivative instruments	16	15
Asset retirement obligations	140	136
Deferred income taxes	1,802	1,785
Other long-term liabilities	14	10
Total liabilities	7,754	7,429
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 164,615,642 issued and outstanding at March 31, 2019; 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 2018	2	2
Additional paid-in capital	13,019	12,936
Retained earnings	752	762
Total Diamondback Energy, Inc. stockholders’ equity	13,773	13,700
Non-controlling interest	741	467
Total equity	14,514	14,167
Total liabilities and equity	$ 22,268	$ 21,596

Consolidated Balance Sheets Con

Consolidated Balance Sheets Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization excluded	$ 9,646	$ 9,670
Common Stock, Par Value (in dollars per share)	$ 0.01	$ 0.01
Shares authorized	200,000,000	200,000,000
Shares Issued	164,615,642	164,273,447
Shares Outstanding	164,615,642	164,273,447

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenues:
Revenue	$ 864	$ 479
Lease bonus	1	0
Other operating income	2	2
Costs and expenses:
Lease operating expenses	109	37
Production and ad valorem taxes	55	27
Depreciation, depletion and amortization	322	115
General and administrative expenses	27	16
Asset retirement obligation accretion	2	1
Other operating expense	1	1
Total costs and expenses	545	212
Income from operations	319	267
Other income (expense):
Interest expense, net	(46)	(14)
Other income, net	1	3
Loss on derivative instruments, net	(268)	(32)
Gain on revaluation of investment	4	1
Total other expense, net	(309)	(42)
Income before income taxes	10	225
Provision for (benefit from) income taxes	(33)	47
Net income	43	178
Net income attributable to non-controlling interest	33	15
Net income attributable to Diamondback Energy, Inc.	$ 10	$ 163
Earnings per common share:
Basic (in dollars per share)	$ 0.06	$ 1.65
Diluted (in dollars per share)	$ 0.06	$ 1.65
Weighted average common shares outstanding:
Basic (in shares)	164,852	98,555
Diluted (in shares)	165,061	98,769
Dividends declared per share	$ 0.1875	$ 0.125
Oil sales
Revenues:
Revenue	$ 743	$ 419
Natural gas sales
Revenues:
Revenue	29	14
Natural gas liquid sales
Revenues:
Revenue	70	33
Midstream services
Revenues:
Revenue	19	11
Costs and expenses:
Cost of Goods and Services Sold	17	11
Gathering and transportation
Costs and expenses:
Cost of Goods and Services Sold	$ 12	$ 4

Consolidated Statement of Stock

Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]
Balance at beginning of period at Dec. 31, 2017	$ 5,582	$ 1	$ 5,291	$ (37)	$ 327
Balance at beginning of period, shares at Dec. 31, 2017		98,167,000
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	1	$ 0	0	0	1
Stock-based compensation	9	0	9	0	0
Distribution to non-controlling interest	(19)	0	0	0	(19)
Exercise of stock options and vesting of restricted stock units	0	$ 0	0	0	0
Exercise of stock options and awards of restricted stock, shares		443,000
Net income	178	$ 0	0	163	15
Balance at end of period at Mar. 31, 2018	5,735	$ 1	5,300	117	317
Balance at end of period, shares at Mar. 31, 2018		98,610,000
Increase (Decrease) in Stockholders' Equity
Impact of adoption of ASU 2016-01, net of tax	(16)	$ 0	0	(9)	(7)
Balance at beginning of period at Dec. 31, 2018	$ 14,167	$ 2	12,936	762	467
Balance at beginning of period, shares at Dec. 31, 2018	164,273,447	164,273,000
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units - Viper Energy Partners LP	$ 341	$ 0	0	0	341
Stock-based compensation	19	0	19	0	0
Repurchased shares for tax withholding	(13)	$ 0	(13)	0	0
Repurchased shares for tax withholding, shares		(125,000)
Distribution to non-controlling interest	(26)	$ 0	0	0	(26)
Dividend paid	(20)	0	0	(20)	0
Exercise of stock options and vesting of restricted stock units	0	$ 0	0	0	0
Exercise of stock options and awards of restricted stock, shares		468,000
Change in ownership of consolidated subsidiaries, net	3	$ 0	77	0	(74)
Net income	43	0	0	10	33
Balance at end of period at Mar. 31, 2019	$ 14,514	$ 2	$ 13,019	$ 752	$ 741
Balance at end of period, shares at Mar. 31, 2019	164,615,642	164,616,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flows from operating activities:
Net income	$ 43	$ 178
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	(33)	47
Asset retirement obligation accretion	2	1
Depreciation, depletion and amortization	322	115
Amortization of debt issuance costs	1	1
Change in fair value of derivative instruments	285	0
Income from equity investment	0	(2)
Gain on revaluation of investment	(4)	(1)
Equity-based compensation expense	14	7
Changes in operating assets and liabilities:
Accounts receivable	(63)	6
Inventories	(4)	(13)
Prepaid expenses and other	(9)	(7)
Accounts payable and accrued liabilities	(190)	(17)
Accrued interest	5	11
Revenues and royalties payable	8	13
Net cash provided by operating activities	377	339
Cash flows from investing activities:
Additions to oil and natural gas properties	(569)	(280)
Additions to midstream assets	(58)	(38)
Purchase of other property, equipment and land	(4)	(2)
Acquisition of leasehold interests	(75)	(16)
Acquisition of mineral interests	(82)	(150)
Investment in real estate	0	(110)
Funds held in escrow	0	11
Equity investments	(149)	0
Net cash used in investing activities	(937)	(585)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	484	224
Repayment under credit facility	(314)	(308)
Proceeds from senior notes	0	312
Proceeds from joint venture	23	0
Debt issuance costs	(3)	(3)
Proceeds from public offerings	341	0
Repurchased shares for tax withholding	(13)	0
Dividends to stockholders	(21)	0
Distributions to non-controlling interest	(26)	(19)
Net cash provided by financing activities	471	206
Net decrease in cash and cash equivalents	(89)	(40)
Cash and cash equivalents at beginning of period	215	112
Cash and cash equivalents at end of period	126	72
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	17	4
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	(10)	41
Capitalized stock-based compensation	6	3
Asset retirement obligations acquired	$ 3	$ 0

Description of the Business and

Description of the Business and Basis of Presentation	3 Months Ended
	Mar. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Business and Basis of Presentation	DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION Organization and Description of the Business Diamondback Energy, Inc. (“Diamondback” or the “Company”), together with its subsidiaries, is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011. The wholly-owned subsidiaries of Diamondback, as of March 31, 2019 , include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, Rattler Midstream GP LLC, a Delaware limited liability company, and Energen Corporation, an Alabama corporation. The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (the “Partnership”), the Partnership’s wholly-owned subsidiary Viper Energy Partners LLC, a Delaware limited liability company (the “Operating Company”), Rattler Midstream LP (formerly known as Rattler Midstream Partners LP), a Delaware limited liability company, Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC), a Delaware limited liability company, and Rattler Midstream Operating LLC’s wholly-owned subsidiary Tall City Towers LLC, a Delaware limited liability company (“Tall City”). Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation. The Partnership is consolidated in the financial statements of the Company. As of March 31, 2019 , the Company owned approximately 54% of the Partnership’s total units outstanding. The Company’s wholly-owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership. These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2018

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities assumed, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes. Investments Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure its investment at fair value which resulted in a downward adjustment of $19 million to record the impact of this adoption. See Note 16 — Fair Value Measurements . New Accounting Pronouncements Recently Adopted Pronouncements In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles and compressors. The Company has completed the process of reviewing and determining the agreements to which this new guidance applies. Upon adoption effective January 1, 2019, the Company recognized approximately $13 million of right-of-use assets, of which the total amount relates to the Company’s operating leases. In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. See Note 17 — Leases for more information on the adoption of these standards. In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity because the Company currently accounts for nonemployee share-based transactions in the same manner as employee share-based transactions. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on its consolidated financial statements since it does not have a history of credit losses. In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	3 Months Ended
	Mar. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	REVENUE FROM CONTRACTS WITH CUSTOMERS Revenue from Contracts with Customers Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. Oil sales The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations. Natural gas and natural gas liquids sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations. Midstream Revenue Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler Midstream Operating LLC (“Rattler”) provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement. Transaction price allocated to remaining performance obligations The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts. The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such the Company has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. The Company has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less. Contract balances Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2019

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2019
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions Disclosures	ACQUISITIONS Tall City Towers LLC On January 31, 2018, Tall City, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $110 million . Energen Corporation Merger On November 29, 2018, the Company completed its acquisition of Energen Corporation (“Energen”) in an all-stock transaction (the “Merger”), which was accounted for as a business combination. Upon completion of this acquisition, the addition of Energen’s assets increased the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, (ii) approximately 7,200 estimated total net horizontal Permian locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins. Under the terms of the Merger, each share of Energen common stock was converted into 0.6442 of a share of the Company’s common stock. The Company issued approximately 62.8 million shares of its common stock valued at a price of $112.00 per share on the closing date, resulting in total consideration paid by the Company to the former Energen shareholders of approximately $7 billion . In connection with the closing of the Merger, the Company repaid outstanding principal under Energen’s revolving credit facility and assumed all of Energen’s other long-term debt. See Note 10 — Debt for additional information. Purchase Price Allocation The Merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Energen to the identifiable assets acquired and the liabilities assumed based on the fair values on the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of Energen’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. The following table sets forth the Company’s preliminary purchase price allocation as of March 31, 2019 : (In millions) Consideration: Fair value of the Company's common stock issued $ 7,136 Total consideration $ 7,136 Fair value of liabilities assumed: Current liabilities $ 349 Asset retirement obligation 105 Long-term debt 1,099 Noncurrent derivative instruments 17 Deferred income taxes 1,403 Other long-term liabilities 7 Amount attributable to liabilities assumed $ 2,980 Fair value of assets acquired: Total current assets $ 305 Oil and natural gas properties 9,283 Midstream assets 263 Investment in real estate 11 Other property, equipment and land 58 Asset retirement obligation 105 Other postretirement assets 3 Noncurrent income tax receivable, net 76 Other long term assets 12 Amount attributable to assets acquired $ 10,116 Pro Forma Financial Information The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the three months ended March 31, 2018 have been prepared to give effect to the Merger as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Energen’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Energen’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Energen’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Energen assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results. Three Months Ended March 31, 2018 (in millions, except per share amounts) Revenues $ 838 Income from operations $ 418 Net income $ 268 Basic earnings per common share $ 1.66 Diluted earnings per common share $ 1.65

Viper Energy Partners LP

Viper Energy Partners LP	3 Months Ended
	Mar. 31, 2019
Noncontrolling Interest [Abstract]
Viper Energy Partners LP	VIPER ENERGY PARTNERS LP The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. Viper Energy Partners GP LLC, a fully-consolidated subsidiary of Diamondback, serves as the general partner of the Partnership. As of March 31, 2019 , the Company owned approximately 54% of the Partnership’s total units outstanding. Equity Offerings On March 1, 2019, the Partnership completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, the Company owned approximately 54% of the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $341 million , after deducting underwriting discounts and commissions and estimated offering expenses. The Partnership used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under the revolving credit facility and finance acquisitions during the period. As a result of this public offering and the Partnership’s issuance of unit-based compensation, the Company’s ownership percentage in the Partnership was reduced. During the three months ended March 31, 2019 , the Company recorded a $74 million decrease to non-controlling interest in the Partnership with an increase to additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in the Partnership before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet. Recapitalization, Tax Status Election and Related Transactions by Viper In March 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 the Partnership (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to the Partnership the 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of the Partnership’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, the Partnership continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of the Partnership’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and the Company owned the remaining approximately 59% . The Operating Company units and the Partnership’s Class B units owned by the Company are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit). On May 10, 2018, the change in the Partnership’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1 million to the Partnership in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1 million to the Partnership in respect of the Class B units. The Company, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and the Company continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018. Partnership Agreement The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”), requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For each of the three months ended March 31, 2019 and 2018 , the General Partner allocated $1 million to the Partnership. Tax Sharing In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. For the three months ended March 31, 2019 , the Partnership accrued a minimal amount of state income tax expense for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback. Other Agreements The Partnership has entered into a secured revolving credit facility with Wells Fargo, as administrative agent sole book runner and lead arranger. See Note 10 — Debt

Real Estate Assets

Real Estate Assets	3 Months Ended
	Mar. 31, 2019
Real Estate [Abstract]
Real Estate Disclosure	REAL ESTATE ASSETS The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of the Company’s real estate assets including intangible lease assets: Estimated Useful Lives March 31, 2019 December 31, 2018 (Years) (in millions) Buildings 30 $ 103 $ 103 Tenant improvements 15 4 4 Land N/A 1 1 Land improvements 15 1 1 Total real estate assets 109 109 Less: accumulated depreciation (5 ) (4 ) Total investment in land and buildings, net $ 104 $ 105 Weighted Average Useful Lives March 31, 2019 December 31, 2018 (Months) (in millions) In-place lease intangibles 45 $ 11 $ 11 Less: accumulated amortization (4 ) (3 ) In-place lease intangibles, net 7 8 Above-market lease intangibles 45 4 4 Less: accumulated amortization (1 ) (1 ) Above-market lease intangibles, net 3 3 Total intangible lease assets, net $ 10 $ 11

Property and Equipment

Property and Equipment	3 Months Ended
	Mar. 31, 2019
Property, Plant and Equipment [Abstract]
Property and Equipment	PROPERTY AND EQUIPMENT Property and equipment includes the following: March 31, December 31, 2019 2018 (in millions) Oil and natural gas properties: Subject to depletion $ 13,583 $ 12,629 Not subject to depletion 9,646 9,670 Gross oil and natural gas properties 23,229 22,299 Accumulated depletion (1,907 ) (1,599 ) Accumulated impairment (1,144 ) (1,144 ) Oil and natural gas properties, net 20,178 19,556 Midstream assets 762 700 Other property, equipment and land 151 147 Accumulated depreciation (44 ) (31 ) Property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 21,047 $ 20,372 Balance of costs not subject to depletion: Incurred in 2019 $ 186 Incurred in 2018 6,142 Incurred in 2017 2,473 Incurred in 2016 687 Incurred in 2015 158 Total not subject to depletion $ 9,646 The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $13 million and $7 million for the three months ended March 31, 2019 and 2018 , respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three years to five years . Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenue including estimated expenditures (based on current costs) to be incurred in developing and producing the proved reserves, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. At March 31, 2019 , there was $91 million in exploration costs and development costs and $71 million in capitalized interest that was not subject to depletion. At December 31, 2018 , there were $68 million in exploration costs and development costs and $55 million

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS The following table describes the changes to the Company’s asset retirement obligation liability for the following periods: Three Months Ended March 31, 2019 2018 (in millions) Asset retirement obligations, beginning of period $ 136 $ 21 Additional liabilities incurred 1 1 Liabilities acquired 3 — Liabilities settled (2 ) (1 ) Accretion expense 2 1 Asset retirement obligations, end of period 140 22 Less current portion — 1 Asset retirement obligations - long-term $ 140 $ 21

Equity Method Investments

Equity Method Investments	3 Months Ended
	Mar. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	EQUITY METHOD INVESTMENTS In October 2014, the Company obtained a 25% interest in HMW Fluid Management LLC (“HMW LLC”), which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas. On June 30, 2018, HMW LLC’s operating agreement was amended. As a result of the amendment, the Company no longer recognizes an equity investment in HMW LLC but instead consolidates its undivided interest in the salt water disposal assets owned by HMW LLC. In exchange for the Company’s 25% investment, the Company received a 50% undivided ownership interest in two of the four SWD wells and associated assets previously owned by HMW LLC. The Company’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC. For the three months ended March 31, 2019 and the year ended December 31, 2018, the Company did not invest in HMW LLC. For the three months ended March 31, 2019 , the Company did no t record any income from HMW LLC. For the three months ended March 31, 2018 , the Company recorded, in other income, $2 million in income from HMW LLC. On February 1, 2019, the Company obtained a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which is building a pipeline (the “EPIC project”) that, once operational, will transport crude and NGL across Texas for delivery into the Corpus Christi market. As of March 31, 2019, the Company has invested $35 million in the EPIC project and recorded no income. The EPIC project is anticipated to be operational in the second half of 2019. On February 15, 2019, the Company obtained a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which is building a pipeline (the “Gray Oak project”) that, once operational, will transport crude from the Permian to Corpus Christi on the Texas Gulf Coast. As of March 31, 2019, the Company has invested $115 million in the Gray Oak project and recorded, in other income, $50,000 in income related to interest. The Gray Oak project is anticipated to be operational in the second half of 2019. On March 29, 2019, the Company executed a short-term promissory note to Gray Oak. The note allows for borrowing by Gray Oak of up to $123 million at 2.52% interest rate with a maturity date of March 31, 2022. There were no borrowings by Gray Oak under the note in the first quarter of 2019. No impairments were recorded for the Company’s equity method investment for the three months ended March 31, 2019 or 2018

Debt

Debt	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Debt	DEBT Long-term debt consisted of the following as of the dates indicated: March 31, December 31, 2019 2018 (in millions) 4.625% Notes due 2021 (1) $ 399 $ 400 7.320% Medium-term Notes, Series A, due 2022 (1) 21 20 4.750 % Senior Notes due 2024 1,250 1,250 5.375 % Senior Notes due 2025 800 800 7.350% Medium-term Notes, Series A, due 2027 (1) 11 10 7.125% Medium-term Notes, Series B, due 2028 (1) 109 100 DrillCo Agreement 23 — Unamortized debt issuance costs (24 ) (27 ) Unamortized premium costs 10 10 Revolving credit facility 1,914 1,490 Partnership revolving credit facility 157 411 Total long-term debt $ 4,670 $ 4,464 (1) At the effective time of the Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of these notes (the “Energen Notes”). Diamondback Notes 2024 Senior Notes On October 28, 2016, the Company issued $500 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “existing 2024 Senior Notes”). The existing 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the existing 2024 Senior Notes; provided, however, that the existing 2024 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream Operating LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. On September 25, 2018, the Company issued $750 million aggregate principal amount of new 4.750% Senior Notes due 2024 (the “New 2024 Notes”), which together with the existing Senior Notes are referred to as the 2024 Senior Notes, as additional notes under, and subject to the terms of, the 2024 Indenture. The New 2024 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $741 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2024 Notes. The Company used a portion of the net proceeds from the issuance of the New 2024 Notes to repay the outstanding borrowings under its revolving credit facility and used the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of assets from Ajax Resources, LLC. The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes at a price equal to 100% of the principal amount of the 2024 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes issued prior to such date at a redemption price of 104.750% , plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings. As required under the terms of the registration rights agreement relating to the New 2024 Notes, on March 22, 2019, the Company filed with the SEC its registration Statement on Form S-4 relating to the exchange offer of the New 2024 Notes for substantially identical notes registered under the Securities Act of 1933, as amended. 2025 Senior Notes On December 20, 2016, the Company issued $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “existing 2025 Senior Notes”). The existing 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the existing 2025 Senior Notes, provided, however, that the existing 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream Operating LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. On January 29, 2018, the Company issued $300 million aggregate principal amount of new 5.375% Senior Notes due 2025 (the “New 2025 Notes”), which together with the existing 2025 Senior Notes are referred to as the 2025 Senior Notes, as additional notes under, and subject to the terms of, the 2025 Indenture. The New 2025 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $308 million in net proceeds, after deducting the initial purchaser’s discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2025 Notes. The Company used the net proceeds from the issuance of the New 2025 Notes to repay a portion of the outstanding borrowings under its revolving credit facility. The 2025 Senior Notes were issued under an indenture, dated as of December 20, 2016, among the Company, the guarantors party thereto and Wells Fargo Bank, as the trustee (the “2025 Indenture”). The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. The Company may on any one or more occasions redeem some or all of the 2025 Senior Notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 Senior Notes at a price equal to 100% of the principal amount of the 2025 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes issued prior to such date at a redemption price of 105.375% , plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings. Energen Notes At the effective time of the Merger, Energen became the Company’s wholly owned subsidiary and remained the issuer of $530 million aggregate principal amount of the Energen Notes, issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). The Energen Notes consist of: (1) $400 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $100 million of 7.125% notes due on February 15, 2028, (3) $20 million of 7.32% notes due on July 28, 2022, and (4) $10 million of 7.35% notes due on July 28, 2027. The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as a wholly owned subsidiary of the Company, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen, including any unsecured guaranties by Energen of the Company’s indebtedness and are effectively subordinated to Energen’s senior secured indebtedness, including Energen’s secured guaranty of all borrowings and other obligations under the Company’s revolving credit facility, to the extent of the value of the collateral securing such indebtedness. The Energen Indenture contains certain covenants that, subject to certain exceptions and qualifications, limit Energen’s ability to incur or suffer to exist liens, to enter into sale and leaseback transactions, to consolidate with or merge into any other entity, and to convey, transfer or lease its properties and assets substantially as an entirety to any person or entity. The Energen Indenture does not include a restriction on the payment of dividends. On November 29, 2018, Energen guaranteed the Company’s indebtedness under its credit facility and granted a lien on certain of its assets to secure such indebtedness and, on December 21, 2018, Energen’s subsidiaries guaranteed the Company’s indebtedness under its credit agreement and granted liens on certain of their assets to secure such indebtedness. As a result of such guarantees, under the terms of the 2024 Indenture and the 2025 Indenture, Energen also guaranteed the 2024 Senior Notes and the 2025 Senior Notes. The Company’s Credit Facility The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum credit amount of $5 billion , subject to a borrowing base based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company and Wells Fargo each may request up to two interim redeterminations of the borrowing base during any 12 -month period. Effective March 25, 2019, the Company increased its elected commitment amount from $2 billion to $3 billion . As of March 31, 2019 , the borrowing base was set at $3 billion , the Company had elected a commitment amount of $3 billion and the Company had $2 billion of outstanding borrowings under the revolving credit facility and $1 billion available for future borrowings under its revolving credit facility. Diamondback O&G LLC is the borrower under the credit agreement. As of March 31, 2019 , the credit agreement is guaranteed by the Company, Diamondback E&P LLC, Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC) and Energen and its subsidiaries and will also be guaranteed by any of the Company’s future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% , and 3-month LIBOR plus 1.0% ) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance. As of March 31, 2019 and December 31, 2018 , the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. The Partnership’s Credit Agreement On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, certain other lenders and the Operating Company, the Partnership’s consolidated subsidiary, as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and the Partnership became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, the Partnership, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”) of $555 million , subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12 -month period. As of March 31, 2019 , the borrowing base was set at $555 million , and the Partnership had $157 million of outstanding borrowings and $398 million available for future borrowings under its revolving credit facility. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Operating Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0% ) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of the Partnership and the Operating Company. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described below: Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of March 31, 2019 and December 31, 2018 , the Partnership was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. Alliance with Obsidian Resources, L.L.C. The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300 million , to fund drilling programs on locations provided by the Company. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15% , while the Company’s interest will increase to 85% . As of March 31, 2019 , CEMOF had funded approximately $18 million . As of March 31, 2019 , six

Capital Stock and Earnings Per

Capital Stock and Earnings Per Share	3 Months Ended
	Mar. 31, 2019
Equity [Abstract]
Capital Stock and Earnings Per Share	CAPITAL STOCK AND EARNINGS PER SHARE Diamondback did not complete any equity offerings during the three months ended March 31, 2019 and March 31, 2018 . Partnership Equity Offerings On March 1, 2019, the Partnership completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, the Company owned approximately 54% of the Partnership’s total units then outstanding. The Partnership received net proceeds from this offering of approximately $341 million , after deducting underwriting discounts and commissions and estimated offering expenses. The Partnership used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility and finance acquisitions during the period. Earnings Per Share The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Three Months Ended March 31, 2019 2018 ($ in millions, except per share amounts, shares in thousands) Net income attributable to common stock $ 10 $ 163 Weighted average common shares outstanding Basic weighted average common units outstanding 164,852 98,555 Effect of dilutive securities: Potential common shares issuable 209 214 Diluted weighted average common shares outstanding 165,061 98,769 Basic net income attributable to common stock $ 0.06 $ 1.65 Diluted net income attributable to common stock $ 0.06 $ 1.65 The Company had the following shares that were excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods: Three Months Ended March 31, 2019 2018 (in thousands) Restricted stock units 31 —

Equity-Based Compensation

Equity-Based Compensation	3 Months Ended
	Mar. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Based Compensation	EQUITY-BASED COMPENSATION The following table presents the effects of the equity compensation plans and related costs: Three Months Ended March 31, 2019 2018 (in millions) General and administrative expenses $ 14 $ 8 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties 6 3 Restricted Stock Units The following table presents the Company’s restricted stock units activity under the Equity Plan during the three months ended March 31, 2019 : Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2018 324,224 $ 116.01 Granted 435,049 $ 107.30 Vested (119,477 ) $ 109.05 Forfeited (9,652 ) $ 112.27 Unvested at March 31, 2019 630,144 $ 111.37 The aggregate fair value of restricted stock units that vested during the three months ended March 31, 2019 and 2018 was $13 million and $9 million , respectively. As of March 31, 2019 , the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $55 million . Such cost is expected to be recognized over a weighted-average period of 1.3 years . Performance Based Restricted Stock Units To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three -year performance period. In March 2019, eligible employees received performance restricted stock unit awards totaling 199,723 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2019 to December 31, 2021 and cliff vest at December 31, 2021. In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2019 to December 31, 2021 and vest in five equal installments beginning on March 1, 2025. The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period. The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the March 2019 awards. 2019 Grant-date fair value (3-year vesting) $ 137.22 Grant-date fair value (5-year vesting) $ 132.48 Risk-free rate 2.55 % Company volatility 35.00 % The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the three months ended March 31, 2019 : Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2018 196,203 $ 169.76 Granted 356,227 $ 131.30 Vested (123,546 ) $ 121.41 Unvested at March 31, 2019 (1) 428,884 $ 151.74 (1) A maximum of 857,768 units could be awarded based upon the Company’s final TSR ranking. As of March 31, 2019 , the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $47 million . Such cost is expected to be recognized over a weighted-average period of 1.4 years . Stock Appreciation Rights In connection with the Energen merger, each outstanding stock appreciation right in respect of Energen common stock that was outstanding immediately prior to the effective time of the Merger was converted into a fully vested stock appreciation right in respect of such number of whole shares of Diamondback common stock (rounded down to the nearest whole share) equal to the product of (A) the total number of shares of Energen common stock subject to such stock appreciation right immediately prior to the effective time of the Merger multiplied by (B) the exchange ratio, at an exercise price per share of Diamondback common stock (rounded up to the nearest whole cent) equal to the quotient of (A) the exercise price per share of Energen common stock of such stock appreciation right immediately prior to the effective time of the Merger divided by (B) the exchange ratio. These awards have a three-year requisite service period. The following table presents a summary of stock appreciation rights activity during the three months ended March 31, 2019 : Shares Weighted Average Exercise Price Outstanding at December 31, 2018 57,721 $ 22.12 Exercised (7,111 ) $ 20.18 Expired (8,691 ) $ 23.29 Outstanding at March 31, 2019 41,919 $ 24.74 Stock Options In connection with the Energen Merger, each option to purchase shares of Energen common stock that was outstanding immediately prior to the effective time of the Merger was converted into a fully vested option to purchase such number of whole shares of Diamondback common stock (rounded down to the nearest whole share) equal to the product of (A) the total number of shares of Energen common stock subject to such option immediately prior to the effective time of the Merger multiplied by (B) the exchange ratio, at an exercise price per share of Diamondback common stock (rounded up to the nearest whole cent) equal to the quotient of (A) the exercise price per share of Energen common stock of such option immediately prior to the effective time of the Merger divided by (B) the exchange ratio. The exercise price of stock options granted may not be less than the market value of the stock at the date of grant. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The expected term of options granted was determined based on the contractual term of the awards at effective time of the merger. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. All such amounts represent the weighted-average amounts for each year. Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in millions) Outstanding at December 31, 2018 332,387 $ 95.04 Granted — $ — Outstanding at March 31, 2019 332,387 $ 95.04 2.49 $ 14 Vested and Expected to vest at March 31, 2019 332,387 $ 95.04 2.49 $ 14 Exercisable at March 31, 2019 332,387 $ 95.04 2.49 $ 14 Phantom Units Under the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of the Partnership for each phantom unit. The following table presents the phantom unit activity under the Viper LTIP for the three months ended March 31, 2019 . Phantom Units Weighted Average Grant-Date Unvested at December 31, 2018 125,053 $ 23.44 Granted 11,001 $ 33.30 Vested (60,133 ) $ 21.38 Unvested at March 31, 2019 75,921 $ 26.51 The aggregate fair value of phantom units that vested during the three months ended March 31, 2019 was $1 million . As of March 31, 2019 , the unrecognized compensation cost related to unvested phantom units was $2 million . Such cost is expected to be recognized over a weighted-average period of 0.99 years

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS Advisory Services Agreement - The Partnership In connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $500,000 , plus reasonable out-of-pocket expenses. For the three months ended March 31, 2019 and 2018 , the Partnership did no t pay any amounts under the Advisory Services Agreement. The Advisory Services Agreement was terminated on November 12, 2018; however, the Partnership’s payment obligation thereunder continues through the end of the current term in June 2019. Lease Bonus - The Partnership During the three months ended March 31, 2019 , the Company paid the Partnership $198 in lease bonus payments to extend the term of one lease, reflecting an average bonus of $125 per acre and $3,101 in lease bonus payments for two new leases, reflecting an average bonus of $14,766 per acre. During the three months ended March 31, 2018 , the Company did no

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Income Tax Disclosure	INCOME TAXES The Company’s effective income tax rates were (301.7)% and 20.9% for the three months ended March 31, 2019 and 2018 , respectively. Total income tax expense for the three months ended March 31, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to (i) the revision of estimated deferred taxes recognized by the Partnership as a result of its change in tax status, (ii) current and deferred state income taxes, and (iii) the impact of permanent differences between book and taxable income. The Company recorded a discrete income tax benefit of less than $1 million related to equity-based compensation for the three months ended March 31, 2019 and a discrete benefit of approximately $35 million related to the revision of estimated deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s tax status. The Partnership revised its estimate of deferred taxes on the Partnership’s investment in the Operating Company based on information regarding unitholders’ tax basis which, under IRS reporting rules, was not available until the current period. Total income tax expense for the three months ended March 31, 2018 differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to state income taxes, net income attributable to the noncontrolling interest, and the impact of permanent differences between book and taxable income. As discussed further in Note 5 , on March 29, 2018, the Partnership announced that the Board of Directors of its General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. The transactions undertaken in connection with the change in the Partnership’s tax status were not taxable to the Company. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the period ended March 31, 2019

Derivatives

Derivatives	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	DERIVATIVES All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the combined consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” The Company has used fixed price swap contracts, fixed price basis swap contracts and three-way costless collars with corresponding put, short put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap or basis price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. The Company has fixed price basis swaps for the spread between the WTI Magellan East Houston oil price and the WTI Cushing price and for the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. Under the Company’s costless collar contracts, a three-way collar is a combination of three options: a ceiling call, a floor put, and a short put. The counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the ceiling price to a maximum of the difference between the floor price and the short put price. The Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the ceiling price. If the settlement price is between the floor and the ceiling price, there is no payment required. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and ICE Brent pricing, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing and liquids derivative settlements based on Mt. Belvieu pricing. By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk. As of March 31, 2019 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2019 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 7,758,000 $ 61.10 — $ — Oil Swaps - WTI Magellan East Houston 1,008,000 $ 69.27 — $ — Oil Swaps - BRENT 1,375,000 $ 67.22 — $ — Oil Basis Swaps - WTI Cushing 12,966,000 $ (5.42 ) 15,120,000 $ (1.21 ) Natural Gas Swaps - Henry Hub 19,250,000 $ 3.06 — $ — Natural Gas Basis Swaps - Waha Hub 19,250,000 $ (1.56 ) — $ — Natural Gas Liquid Swaps - Mont Belvieu 2,070,000 $ 27.30 — $ — 2019 2020 Oil Three-Way Collars WTI Cushing Brent WTI Magellan East Houston Brent WTI Magellan East Houston Volume (Bbls) 5,230,000 1,648,000 1,284,000 3,660,000 2,190,000 Short put price (per Bbl) $ 37.51 $ 53.88 $ 52.13 $ 50.00 $ 50.00 Floor price (per Bbl) $ 47.51 $ 63.88 $ 62.13 $ 60.00 $ 60.00 Ceiling price (per Bbl) $ 63.05 $ 80.09 $ 69.38 $ 74.63 $ 66.90 Balance sheet offsetting of derivative assets and liabilities The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of March 31, 2019 and December 31, 2018 . March 31, 2019 December 31, 2018 (in millions) Gross amounts of assets presented in the Consolidated Balance Sheet $ 5 $ 231 Net amounts of assets presented in the Consolidated Balance Sheet 5 231 Gross amounts of liabilities presented in the Consolidated Balance Sheet 74 15 Net amounts of liabilities presented in the Consolidated Balance Sheet $ 74 $ 15 The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: March 31, 2019 December 31, 2018 (in millions) Current assets: derivative instruments $ 5 $ 231 Noncurrent assets: derivative instruments — — Total assets $ 5 $ 231 Current liabilities: derivative instruments $ 58 $ — Noncurrent liabilities: derivative instruments 16 15 Total liabilities $ 74 $ 15 None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations: Three Months Ended March 31, 2019 2018 (in millions) Change in fair value of open non-hedge derivative instruments $ (285 ) $ — Gain (loss) on settlement of non-hedge derivative instruments 17 (32 ) Loss on derivative instruments $ (268 ) $ (32 )

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below. The Company estimates asset retirement obligations pursuant to the provisions of the Financial Accounting Standards Board issued Accounting Standards Codification Topic 410, “Asset Retirement and Environmental Obligations”. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 8—Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments and the Partnership’s cost method investment. The fair value of the Partnership’s investment is determined using quoted market prices. These valuations are Level 1 inputs. The fair values of the Company’s fixed price swaps, fixed price basis swaps and costless collars are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs. The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2019 and December 31, 2018 . March 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in millions) Assets: Investment $ 18 $ — $ — $ 14 $ — $ — Fixed price swaps — — — — 216 — Liabilities: Fixed price swaps $ — $ 69 $ — $ — $ — $ — The following table summarizes the changes in fair value of the Partnership’s cost method investment during the periods presented: (in millions) Value at December 31, 2017 $ 34 Impact of adoption of Accounting Standards Update 2016-01 (19 ) Gain on investment 1 Value at March 31, 2018 $ 16 Value at December 31, 2018 $ 14 Gain on investment 4 Value at March 31, 2019 $ 18 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets: March 31, 2019 December 31, 2018 Carrying Carrying Amount Fair Value Amount Fair Value (in millions) Debt: Revolving credit facility $ 1,914 $ 1,914 $ 1,490 $ 1,490 4.625% Notes due 2021 (1) $ 399 $ 404 $ 400 $ 393 7.320% Medium-term Notes, Series A, due 2022 (1) $ 21 $ 22 $ 20 $ 21 4.750% Senior Notes due 2024 $ 1,250 $ 1,283 $ 1,250 $ 1,204 5.375% Senior Notes due 2025 $ 800 $ 838 $ 800 $ 782 7.350% Medium-term Notes, Series A, due 2027 (1) $ 11 $ 11 $ 10 $ 11 7.125% Medium-term Notes, Series B, due 2028 (1) $ 109 $ 110 $ 100 $ 102 Partnership revolving credit facility $ 157 $ 157 $ 411 $ 411 DrillCo Agreement $ 23 $ 23 $ — $ — (1) At the effective time of the Energen Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of the Energen Notes. These notes were marked to fair value with the excess being amortized. The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes and the Energen Notes was determined using the March 31, 2019

Leases

Leases	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Lessee, Operating Leases [Text Block]	LEASES The Company leases certain drilling rigs, facilities, compression and other equipment. As discussed in Note 2—Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Company elected the following practical expedients: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; (iii) to not reassess lease terms for lease terms on leases entered into prior to the effective date of adoption; and (iv) lessor accounting policy election to exclude lessor costs paid directly by the lessee. For leases where the Company is the lessee, the Company recorded a total of $13 million in right-of-use assets and corresponding new lease liabilities in other on its Condensed Consolidated Balance Sheet representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of twelve months or less are considered short-term leases and are not recorded on the balance sheet. The following table summarizes operating lease costs for the three months ended March 31, 2019 : Three Months Ended March 31, 2019 (in millions) Operating lease costs $ 4 For the three months ended March 31, 2019 , cash paid for operating lease liabilities, and reported in cash flows provided by operating activities on the Company's Statement of Condensed Consolidated Cash Flows, was $5 million . During the three months ended March 31, 2019 , the Company recorded an additional $8 million of right-of-use assets in exchange for new lease liabilities. The operating lease right-of-use assets were reported in other assets and the current and noncurrent portions of the operating lease liabilities were reported in other current liabilities and other liabilities, respectively, on the Condensed Consolidated Balance Sheet. As of March 31, 2019 , the operating right-of-use assets were $26 million and operating lease liabilities were $26 million , of which $21 million was classified as current. As of March 31, 2019 , the weighted average remaining lease term was 1.4 years and the weighted average discount rate was 8.4% . Schedule of Operating Lease Liability Maturities . The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of March 31, 2019 : As of March 31, 2019 (in millions) 2019 (April - December) $ 22 2020 4 2021 1 2022 — 2023 — Thereafter — Total lease payments 27 Less: interest 1 Present value of lease liabilities $ 26

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS First Quarter 2019 Dividend Declaration On May 3, 2019 , the Board of Directors of the Company declared a cash dividend for the first quarter of 2019 of $0.1875 per share of common stock, payable on June 4, 2019 to its stockholders of record at the close of business on May 28, 2019 . Commodity Contracts Subsequent to March 31, 2019 , the Company entered into new fixed price basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil Brent. The following tables present the derivative contracts entered into by the Company subsequent to March 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) July 2019 - December 2019 Oil Swaps - WTI 368,000 $ 61.72 Oil Swaps - WTI Magellan East Houston 828,000 $ 65.61 Oil Swaps - BRENT 368,000 $ 69.45 January 2020 - December 2020 Oil Swaps - WTI 2,562,000 $ 60.63 Oil Swaps - WTI Magellan East Houston 1,464,000 $ 64.25 Oil Swaps - BRENT 1,464,000 $ 66.24 July 2019 - December 2019 January 2020 - December 2020 Oil Three-Way Collars Brent WTI Brent WTI - Magellan East Houston Volume (Bbls) 368,000 2,928,000 2,196,000 2,928,000 Short put price (per Bbl) $ 50.00 $ 45.00 $ 51.67 $ 50.00 Floor price (per Bbl) $ 60.00 $ 55.00 $ 61.67 $ 60.00 Ceiling price (per Bbl) $ 77.50 $ 67.00 $ 74.92 $ 69.90 Gray Oak Promissory Note As of May 2, 2019, borrowings due the Company totaled $23 million . The note is expected to be repaid in full before the end of the second quarter 2019 when Gray Oak expects to secure bank financing for construction. Stock Repurchase Program In May 2019, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock through December 31, 2020. This repurchase program is another component of the Company’s capital return program that includes the increased quarterly dividend. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Pending Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen In May 2019, the Company entered into two definitive agreements with unrelated third-party purchasers to divest 103,423 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the Merger, for an aggregate sale price of $322 million

Guarantor Financial Statements

Guarantor Financial Statements	3 Months Ended
	Mar. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Guarantor Financial Statements	GUARANTOR FINANCIAL STATEMENTS As of March 31, 2019 , Diamondback E&P LLC, Diamondback O&G LLC and Energen Corporation and its subsidiaries (the “Guarantor Subsidiaries”) are guarantors under the 2024 Indenture and the 2025 Indenture. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes, the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream Operating LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 20 Condensed Consolidated Balance Sheet March 31, 2019 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 121 $ (5 ) $ 10 $ — $ 126 Accounts receivable, net — 425 38 — 463 Accounts receivable - related party — — 7 (7 ) — Intercompany receivable 3,985 1,356 — (5,341 ) — Inventories — 39 — — 39 Derivative instruments — 5 — — 5 Prepaid expenses and other 1 59 — — 60 Total current assets 4,107 1,879 55 (5,348 ) 693 Property and equipment: Oil and natural gas properties, at cost, full cost method of accounting — 21,434 1,798 (3 ) 23,229 Midstream assets — 762 — — 762 Other property, equipment and land — 145 6 — 151 Accumulated depletion, depreciation, amortization and impairment — (2,812 ) (264 ) (19 ) (3,095 ) Net property and equipment — 19,529 1,540 (22 ) 21,047 Equity method investments — 150 — — 150 Investment in subsidiaries 12,221 123 — (12,344 ) — Deferred tax asset — — 150 — 150 Investment in real estate, net — 114 — — 114 Other assets — 92 22 — 114 Total assets $ 16,328 $ 21,887 $ 1,767 $ (17,714 ) $ 22,268 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 180 $ — $ — $ 180 Intercompany payable 81 5,267 — (5,348 ) — Accrued capital expenditures — 485 — — 485 Other accrued liabilities 39 196 3 — 238 Revenues and royalties payable — 151 — — 151 Derivative instruments — 58 — — 58 Total current liabilities 120 6,337 3 (5,348 ) 1,112 Long-term debt 2,036 2,477 157 — 4,670 Derivative instruments — 16 — — 16 Asset retirement obligations — 140 — — 140 Deferred income taxes 399 1,403 — — 1,802 Other long-term liabilities — 14 — — 14 Total liabilities 2,555 10,387 160 (5,348 ) 7,754 Commitments and contingencies Stockholders’ equity 13,773 11,500 819 (12,319 ) 13,773 Non-controlling interest — — 788 (47 ) 741 Total equity 13,773 11,500 1,607 (12,366 ) 14,514 Total liabilities and equity $ 16,328 $ 21,887 $ 1,767 $ (17,714 ) $ 22,268 Condensed Consolidated Balance Sheet December 31, 2018 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 84 $ 108 $ 23 $ — $ 215 Accounts receivable — 354 38 — 392 Accounts receivable - related party — — 3 (3 ) — Intercompany receivable 4,469 201 — (4,670 ) — Inventories — 37 — — 37 Derivative instruments — 231 — — 231 Prepaid expenses and other 3 47 — — 50 Total current assets 4,556 978 64 (4,673 ) 925 Property and equipment: Oil and natural gas properties, at cost, full cost method of accounting — 20,586 1,717 (4 ) 22,299 Midstream assets — 700 — — 700 Other property, equipment and land — 141 6 — 147 Accumulated depletion, depreciation, amortization and impairment — (2,514 ) (248 ) (12 ) (2,774 ) Net property and equipment — 18,913 1,475 (16 ) 20,372 Equity method investments — 1 — — 1 Investment in subsidiaries 11,576 112 — (11,688 ) — Investment in real estate, net — 116 — — 116 Deferred tax asset — — 97 — 97 Other assets — 67 18 — 85 Total assets $ 16,132 $ 20,187 $ 1,654 $ (16,377 ) $ 21,596 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 128 $ — $ — $ 128 Intercompany payable — 4,673 — (4,673 ) — Accrued capital expenditures — 495 — — 495 Other accrued liabilities 14 233 6 — 253 Revenues and royalties payable — 143 — — 143 Total current liabilities 14 5,672 6 (4,673 ) 1,019 Long-term debt 2,036 2,017 411 — 4,464 Derivative instruments — 15 — — 15 Asset retirement obligations — 136 — — 136 Deferred income taxes 382 1,403 — — 1,785 Other long-term liabilities — 10 — — 10 Total liabilities 2,432 9,253 417 (4,673 ) 7,429 Commitments and contingencies Stockholders’ equity 13,700 10,934 542 (11,476 ) 13,700 Non-controlling interest — — 695 (228 ) 467 Total equity 13,700 10,934 1,237 (11,704 ) 14,167 Total liabilities and equity $ 16,132 $ 20,187 $ 1,654 $ (16,377 ) $ 21,596 Condensed Consolidated Statement of Operations Three Months Ended March 31, 2019 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 691 $ — $ 52 $ 743 Natural gas sales — 25 — 4 29 Natural gas liquid sales — 66 — 4 70 Royalty income — — 60 (60 ) — Lease bonus — — 1 — 1 Midstream services — 19 — — 19 Other operating income — 2 — — 2 Total revenues — 803 61 — 864 Costs and expenses: Lease operating expenses — 109 — — 109 Production and ad valorem taxes — 51 4 — 55 Gathering and transportation — 12 — — 12 Midstream services — 17 — — 17 Depreciation, depletion and amortization — 300 16 6 322 General and administrative expenses 15 11 1 — 27 Asset retirement obligation accretion — 2 — — 2 Other operating expense — 1 — — 1 Total costs and expenses 15 503 21 6 545 Income (loss) from operations (15 ) 300 40 (6 ) 319 Other income (expense) Interest expense, net (10 ) (30 ) (6 ) — (46 ) Other income (expense), net — 1 — — 1 Loss on derivative instruments, net — (268 ) — — (268 ) Gain on revaluation of investment — — 4 — 4 Total other expense, net (10 ) (297 ) (2 ) — (309 ) Income (loss) before income taxes (25 ) 3 38 (6 ) 10 Provision for income taxes 2 — (35 ) — (33 ) Net income (loss) (27 ) 3 73 (6 ) 43 Net income attributable to non-controlling interest — — 40 (7 ) 33 Net income (loss) attributable to Diamondback Energy, Inc. $ (27 ) $ 3 $ 33 $ 1 $ 10 Condensed Consolidated Statement of Operations Three Months Ended March 31, 2018 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 364 $ — $ 55 $ 419 Natural gas sales — 12 — 2 14 Natural gas liquid sales — 29 — 4 33 Royalty income — — 62 (62 ) — Midstream services — 11 — — 11 Other operating income — 2 — — 2 Total revenues — 418 62 (1 ) 479 Costs and expenses: Lease operating expenses — 37 — — 37 Production and ad valorem taxes — 23 4 — 27 Gathering and transportation — 4 — — 4 Midstream services — 11 — — 11 Depreciation, depletion and amortization — 100 12 3 115 General and administrative expenses 7 7 2 — 16 Asset retirement obligation accretion — 1 — — 1 Other operating expense — 1 — — 1 Total costs and expenses 7 184 18 3 212 Income (loss) from operations (7 ) 234 44 (4 ) 267 Other income (expense) Interest expense, net (9 ) (3 ) (2 ) — (14 ) Other income (expense), net — 3 — — 3 Loss on derivative instruments, net — (32 ) — — (32 ) Gain on revaluation of investment — — 1 — 1 Total other expense, net (9 ) (32 ) (1 ) — (42 ) Income (loss) before income taxes (16 ) 202 43 (4 ) 225 Provision for income taxes 47 — — — 47 Net income (loss) (63 ) 202 43 (4 ) 178 Net income attributable to non-controlling interest — — — 15 15 Net income (loss) attributable to Diamondback Energy, Inc. $ (63 ) $ 202 $ 43 $ (19 ) $ 163 Condensed Consolidated Statement of Cash Flows Three Months Ended March 31, 2019 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ 16 $ 316 $ 45 $ — $ 377 Cash flows from investing activities: Additions to oil and natural gas properties — (569 ) — — (569 ) Additions to midstream assets — (58 ) — — (58 ) Purchase of other property, equipment and land — (4 ) — — (4 ) Acquisition of leasehold interests — (75 ) — — (75 ) Acquisition of mineral interests — — (82 ) — (82 ) Equity investments — (149 ) — — (149 ) Net cash used in investing activities — (855 ) (82 ) — (937 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 424 60 — 484 Repayment under credit facility — — (314 ) — (314 ) Proceeds from joint venture — 23 — — 23 Debt issuance costs — (3 ) — — (3 ) Proceeds from public offerings — — 341 — 341 Distributions from subsidiary 37 — — (37 ) — Dividends to stockholders (21 ) — — — (21 ) Repurchased for tax withholdings (13 ) — — — (13 ) Distributions to non-controlling interest — — (63 ) 37 (26 ) Intercompany transfers 18 (18 ) — — — Net cash provided by financing activities 21 426 24 — 471 Net increase (decrease) in cash and cash equivalents 37 (113 ) (13 ) — (89 ) Cash and cash equivalents at beginning of period 84 108 23 — 215 Cash and cash equivalents at end of period $ 121 $ (5 ) $ 10 $ — $ 126 Condensed Consolidated Statement of Cash Flows Three Months Ended March 31, 2018 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ 27 $ 263 $ 49 $ — $ 339 Cash flows from investing activities: Additions to oil and natural gas properties — (280 ) — — (280 ) Additions to midstream assets — (38 ) — — (38 ) Purchase of other property, equipment and land — (2 ) — — (2 ) Acquisition of leasehold interests — (16 ) — — (16 ) Acquisition of mineral interests — — (150 ) — (150 ) Funds held in escrow — 11 — — 11 Intercompany transfers (87 ) 87 — — — Investment in real estate — (110 ) — — (110 ) Net cash used in investing activities (87 ) (348 ) (150 ) — (585 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 77 147 — 224 Repayment under credit facility — (308 ) — — (308 ) Proceeds from senior notes 312 — — — 312 Debt issuance costs (3 ) — — — (3 ) Distributions from subsidiary 33 — — (33 ) — Distributions to non-controlling interest — — (52 ) 33 (19 ) Intercompany transfers (308 ) 308 — — — Net cash provided by financing activities 34 77 95 — 206 Net increase (decrease) in cash and cash equivalents (26 ) (8 ) (6 ) — (40 ) Cash and cash equivalents at beginning of period 54 34 24 — 112 Cash and cash equivalents at end of period $ 28 $ 26 $ 18 $ — $ 72

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation
Use of Estimates	Use of Estimates Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Pronouncements In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles and compressors. The Company has completed the process of reviewing and determining the agreements to which this new guidance applies. Upon adoption effective January 1, 2019, the Company recognized approximately $13 million of right-of-use assets, of which the total amount relates to the Company’s operating leases. In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. See Note 17 — Leases for more information on the adoption of these standards. In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity because the Company currently accounts for nonemployee share-based transactions in the same manner as employee share-based transactions. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on its consolidated financial statements since it does not have a history of credit losses. In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.
Equity Method Investments	Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision.
Revenue Recognition	Revenue from Contracts with Customers Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. Oil sales The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations. Natural gas and natural gas liquids sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations. Midstream Revenue Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler Midstream Operating LLC (“Rattler”) provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement. Transaction price allocated to remaining performance obligations The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts. The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such the Company has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. The Company has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less. Contract balances Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2019
Fair Value Measurement	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Acquisitions (Tables)

Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2019
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table sets forth the Company’s preliminary purchase price allocation as of March 31, 2019 : (In millions) Consideration: Fair value of the Company's common stock issued $ 7,136 Total consideration $ 7,136 Fair value of liabilities assumed: Current liabilities $ 349 Asset retirement obligation 105 Long-term debt 1,099 Noncurrent derivative instruments 17 Deferred income taxes 1,403 Other long-term liabilities 7 Amount attributable to liabilities assumed $ 2,980 Fair value of assets acquired: Total current assets $ 305 Oil and natural gas properties 9,283 Midstream assets 263 Investment in real estate 11 Other property, equipment and land 58 Asset retirement obligation 105 Other postretirement assets 3 Noncurrent income tax receivable, net 76 Other long term assets 12 Amount attributable to assets acquired $ 10,116
Business Acquisition, Pro Forma Information	The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results. Three Months Ended March 31, 2018 (in millions, except per share amounts) Revenues $ 838 Income from operations $ 418 Net income $ 268 Basic earnings per common share $ 1.66 Diluted earnings per common share $ 1.65

Real Estate Assets (Tables)

Real Estate Assets (Tables)	3 Months Ended
	Mar. 31, 2019
Real Estate [Abstract]
Schedule of Real Estate Assets	The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of the Company’s real estate assets including intangible lease assets: Estimated Useful Lives March 31, 2019 December 31, 2018 (Years) (in millions) Buildings 30 $ 103 $ 103 Tenant improvements 15 4 4 Land N/A 1 1 Land improvements 15 1 1 Total real estate assets 109 109 Less: accumulated depreciation (5 ) (4 ) Total investment in land and buildings, net $ 104 $ 105 Weighted Average Useful Lives March 31, 2019 December 31, 2018 (Months) (in millions) In-place lease intangibles 45 $ 11 $ 11 Less: accumulated amortization (4 ) (3 ) In-place lease intangibles, net 7 8 Above-market lease intangibles 45 4 4 Less: accumulated amortization (1 ) (1 ) Above-market lease intangibles, net 3 3 Total intangible lease assets, net $ 10 $ 11

Property and Equipment (Tables)

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2019
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and equipment includes the following: March 31, December 31, 2019 2018 (in millions) Oil and natural gas properties: Subject to depletion $ 13,583 $ 12,629 Not subject to depletion 9,646 9,670 Gross oil and natural gas properties 23,229 22,299 Accumulated depletion (1,907 ) (1,599 ) Accumulated impairment (1,144 ) (1,144 ) Oil and natural gas properties, net 20,178 19,556 Midstream assets 762 700 Other property, equipment and land 151 147 Accumulated depreciation (44 ) (31 ) Property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 21,047 $ 20,372 Balance of costs not subject to depletion: Incurred in 2019 $ 186 Incurred in 2018 6,142 Incurred in 2017 2,473 Incurred in 2016 687 Incurred in 2015 158 Total not subject to depletion $ 9,646

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	The following table describes the changes to the Company’s asset retirement obligation liability for the following periods: Three Months Ended March 31, 2019 2018 (in millions) Asset retirement obligations, beginning of period $ 136 $ 21 Additional liabilities incurred 1 1 Liabilities acquired 3 — Liabilities settled (2 ) (1 ) Accretion expense 2 1 Asset retirement obligations, end of period 140 22 Less current portion — 1 Asset retirement obligations - long-term $ 140 $ 21

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2019
Line of Credit Facility [Line Items]
Schedule of long-term debt	Long-term debt consisted of the following as of the dates indicated: March 31, December 31, 2019 2018 (in millions) 4.625% Notes due 2021 (1) $ 399 $ 400 7.320% Medium-term Notes, Series A, due 2022 (1) 21 20 4.750 % Senior Notes due 2024 1,250 1,250 5.375 % Senior Notes due 2025 800 800 7.350% Medium-term Notes, Series A, due 2027 (1) 11 10 7.125% Medium-term Notes, Series B, due 2028 (1) 109 100 DrillCo Agreement 23 — Unamortized debt issuance costs (24 ) (27 ) Unamortized premium costs 10 10 Revolving credit facility 1,914 1,490 Partnership revolving credit facility 157 411 Total long-term debt $ 4,670 $ 4,464
Financial Covenants	Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0
Partnership Credit Facility [Member]
Line of Credit Facility [Line Items]
Financial Covenants	Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0

Capital Stock and Earnings Pe_2

Capital Stock and Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2019
Equity [Abstract]
Schedule of reconciliation of basic and diluted net income per share	A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Three Months Ended March 31, 2019 2018 ($ in millions, except per share amounts, shares in thousands) Net income attributable to common stock $ 10 $ 163 Weighted average common shares outstanding Basic weighted average common units outstanding 164,852 98,555 Effect of dilutive securities: Potential common shares issuable 209 214 Diluted weighted average common shares outstanding 165,061 98,769 Basic net income attributable to common stock $ 0.06 $ 1.65 Diluted net income attributable to common stock $ 0.06 $ 1.65
Schedule of antidilutive securities excluded from computation of earnings per share	The Company had the following shares that were excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods: Three Months Ended March 31, 2019 2018 (in thousands) Restricted stock units 31 —

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
The effects of stock-based compensation plans and related costs	The following table presents the effects of the equity compensation plans and related costs: Three Months Ended March 31, 2019 2018 (in millions) General and administrative expenses $ 14 $ 8 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties 6 3
Summary of restricted stock units	The following table presents the Company’s restricted stock units activity under the Equity Plan during the three months ended March 31, 2019 : Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2018 324,224 $ 116.01 Granted 435,049 $ 107.30 Vested (119,477 ) $ 109.05 Forfeited (9,652 ) $ 112.27 Unvested at March 31, 2019 630,144 $ 111.37
Summary of grant-date fair values of performance restricted stock units granted and related assumptions	The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the March 2019 awards. 2019 Grant-date fair value (3-year vesting) $ 137.22 Grant-date fair value (5-year vesting) $ 132.48 Risk-free rate 2.55 % Company volatility 35.00 %
Schedule of performance restricted stock units activity	The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the three months ended March 31, 2019 : Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2018 196,203 $ 169.76 Granted 356,227 $ 131.30 Vested (123,546 ) $ 121.41 Unvested at March 31, 2019 (1) 428,884 $ 151.74 (1) A maximum of 857,768
Schedule of share-based compensation, stock appreciation rights award activity	The following table presents a summary of stock appreciation rights activity during the three months ended March 31, 2019 : Shares Weighted Average Exercise Price Outstanding at December 31, 2018 57,721 $ 22.12 Exercised (7,111 ) $ 20.18 Expired (8,691 ) $ 23.29 Outstanding at March 31, 2019 41,919 $ 24.74
Schedule of stock options activity	The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The expected term of options granted was determined based on the contractual term of the awards at effective time of the merger. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. All such amounts represent the weighted-average amounts for each year. Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in millions) Outstanding at December 31, 2018 332,387 $ 95.04 Granted — $ — Outstanding at March 31, 2019 332,387 $ 95.04 2.49 $ 14 Vested and Expected to vest at March 31, 2019 332,387 $ 95.04 2.49 $ 14 Exercisable at March 31, 2019 332,387 $ 95.04 2.49 $ 14
Viper Energy Partners LP Long Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units activity	The following table presents the phantom unit activity under the Viper LTIP for the three months ended March 31, 2019 . Phantom Units Weighted Average Grant-Date Unvested at December 31, 2018 125,053 $ 23.44 Granted 11,001 $ 33.30 Vested (60,133 ) $ 21.38 Unvested at March 31, 2019 75,921 $ 26.51

Derivatives (Tables)

Derivatives (Tables)	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative instruments	As of March 31, 2019 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2019 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 7,758,000 $ 61.10 — $ — Oil Swaps - WTI Magellan East Houston 1,008,000 $ 69.27 — $ — Oil Swaps - BRENT 1,375,000 $ 67.22 — $ — Oil Basis Swaps - WTI Cushing 12,966,000 $ (5.42 ) 15,120,000 $ (1.21 ) Natural Gas Swaps - Henry Hub 19,250,000 $ 3.06 — $ — Natural Gas Basis Swaps - Waha Hub 19,250,000 $ (1.56 ) — $ — Natural Gas Liquid Swaps - Mont Belvieu 2,070,000 $ 27.30 — $ — 2019 2020 Oil Three-Way Collars WTI Cushing Brent WTI Magellan East Houston Brent WTI Magellan East Houston Volume (Bbls) 5,230,000 1,648,000 1,284,000 3,660,000 2,190,000 Short put price (per Bbl) $ 37.51 $ 53.88 $ 52.13 $ 50.00 $ 50.00 Floor price (per Bbl) $ 47.51 $ 63.88 $ 62.13 $ 60.00 $ 60.00 Ceiling price (per Bbl) $ 63.05 $ 80.09 $ 69.38 $ 74.63 $ 66.90 March 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) July 2019 - December 2019 Oil Swaps - WTI 368,000 $ 61.72 Oil Swaps - WTI Magellan East Houston 828,000 $ 65.61 Oil Swaps - BRENT 368,000 $ 69.45 January 2020 - December 2020 Oil Swaps - WTI 2,562,000 $ 60.63 Oil Swaps - WTI Magellan East Houston 1,464,000 $ 64.25 Oil Swaps - BRENT 1,464,000 $ 66.24 July 2019 - December 2019 January 2020 - December 2020 Oil Three-Way Collars Brent WTI Brent WTI - Magellan East Houston Volume (Bbls) 368,000 2,928,000 2,196,000 2,928,000 Short put price (per Bbl) $ 50.00 $ 45.00 $ 51.67 $ 50.00 Floor price (per Bbl) $ 60.00 $ 55.00 $ 61.67 $ 60.00 Ceiling price (per Bbl) $ 77.50 $ 67.00 $ 74.92 $ 69.90
Schedule of netting offsets of derivative assets and liabilities	The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of March 31, 2019 and December 31, 2018 . March 31, 2019 December 31, 2018 (in millions) Gross amounts of assets presented in the Consolidated Balance Sheet $ 5 $ 231 Net amounts of assets presented in the Consolidated Balance Sheet 5 231 Gross amounts of liabilities presented in the Consolidated Balance Sheet 74 15 Net amounts of liabilities presented in the Consolidated Balance Sheet $ 74 $ 15
Schedule of derivative instruments included in the consolidated balance sheet	The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: March 31, 2019 December 31, 2018 (in millions) Current assets: derivative instruments $ 5 $ 231 Noncurrent assets: derivative instruments — — Total assets $ 5 $ 231 Current liabilities: derivative instruments $ 58 $ — Noncurrent liabilities: derivative instruments 16 15 Total liabilities $ 74 $ 15
Summary of derivative contract gains and losses included in the consolidated statements of operations	The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations: Three Months Ended March 31, 2019 2018 (in millions) Change in fair value of open non-hedge derivative instruments $ (285 ) $ — Gain (loss) on settlement of non-hedge derivative instruments 17 (32 ) Loss on derivative instruments $ (268 ) $ (32 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair value measurement information for financial instruments measured on a recurring basis	The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2019 and December 31, 2018 . March 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in millions) Assets: Investment $ 18 $ — $ — $ 14 $ — $ — Fixed price swaps — — — — 216 — Liabilities: Fixed price swaps $ — $ 69 $ — $ — $ — $ — The following table summarizes the changes in fair value of the Partnership’s cost method investment during the periods presented: (in millions) Value at December 31, 2017 $ 34 Impact of adoption of Accounting Standards Update 2016-01 (19 ) Gain on investment 1 Value at March 31, 2018 $ 16 Value at December 31, 2018 $ 14 Gain on investment 4 Value at March 31, 2019 $ 18
Fair value measurement information for financial instruments measured on a nonrecurring basis	The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets: March 31, 2019 December 31, 2018 Carrying Carrying Amount Fair Value Amount Fair Value (in millions) Debt: Revolving credit facility $ 1,914 $ 1,914 $ 1,490 $ 1,490 4.625% Notes due 2021 (1) $ 399 $ 404 $ 400 $ 393 7.320% Medium-term Notes, Series A, due 2022 (1) $ 21 $ 22 $ 20 $ 21 4.750% Senior Notes due 2024 $ 1,250 $ 1,283 $ 1,250 $ 1,204 5.375% Senior Notes due 2025 $ 800 $ 838 $ 800 $ 782 7.350% Medium-term Notes, Series A, due 2027 (1) $ 11 $ 11 $ 10 $ 11 7.125% Medium-term Notes, Series B, due 2028 (1) $ 109 $ 110 $ 100 $ 102 Partnership revolving credit facility $ 157 $ 157 $ 411 $ 411 DrillCo Agreement $ 23 $ 23 $ — $ —

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Lease, Cost	The following table summarizes operating lease costs for the three months ended March 31, 2019 : Three Months Ended March 31, 2019 (in millions) Operating lease costs $ 4
Lessee, Operating Lease, Liability, Maturity	Schedule of Operating Lease Liability Maturities . The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of March 31, 2019 : As of March 31, 2019 (in millions) 2019 (April - December) $ 22 2020 4 2021 1 2022 — 2023 — Thereafter — Total lease payments 27 Less: interest 1 Present value of lease liabilities $ 26

Subsequent Events (Tables)

Subsequent Events (Tables)	3 Months Ended
	Mar. 31, 2019
Subsequent Event [Line Items]
Schedule of derivative instruments	As of March 31, 2019 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2019 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 7,758,000 $ 61.10 — $ — Oil Swaps - WTI Magellan East Houston 1,008,000 $ 69.27 — $ — Oil Swaps - BRENT 1,375,000 $ 67.22 — $ — Oil Basis Swaps - WTI Cushing 12,966,000 $ (5.42 ) 15,120,000 $ (1.21 ) Natural Gas Swaps - Henry Hub 19,250,000 $ 3.06 — $ — Natural Gas Basis Swaps - Waha Hub 19,250,000 $ (1.56 ) — $ — Natural Gas Liquid Swaps - Mont Belvieu 2,070,000 $ 27.30 — $ — 2019 2020 Oil Three-Way Collars WTI Cushing Brent WTI Magellan East Houston Brent WTI Magellan East Houston Volume (Bbls) 5,230,000 1,648,000 1,284,000 3,660,000 2,190,000 Short put price (per Bbl) $ 37.51 $ 53.88 $ 52.13 $ 50.00 $ 50.00 Floor price (per Bbl) $ 47.51 $ 63.88 $ 62.13 $ 60.00 $ 60.00 Ceiling price (per Bbl) $ 63.05 $ 80.09 $ 69.38 $ 74.63 $ 66.90 March 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) July 2019 - December 2019 Oil Swaps - WTI 368,000 $ 61.72 Oil Swaps - WTI Magellan East Houston 828,000 $ 65.61 Oil Swaps - BRENT 368,000 $ 69.45 January 2020 - December 2020 Oil Swaps - WTI 2,562,000 $ 60.63 Oil Swaps - WTI Magellan East Houston 1,464,000 $ 64.25 Oil Swaps - BRENT 1,464,000 $ 66.24 July 2019 - December 2019 January 2020 - December 2020 Oil Three-Way Collars Brent WTI Brent WTI - Magellan East Houston Volume (Bbls) 368,000 2,928,000 2,196,000 2,928,000 Short put price (per Bbl) $ 50.00 $ 45.00 $ 51.67 $ 50.00 Floor price (per Bbl) $ 60.00 $ 55.00 $ 61.67 $ 60.00 Ceiling price (per Bbl) $ 77.50 $ 67.00 $ 74.92 $ 69.90

Guarantor Financial Statements

Guarantor Financial Statements (Tables)	3 Months Ended
	Mar. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidated Balance Sheet	Condensed Consolidated Balance Sheet March 31, 2019 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 121 $ (5 ) $ 10 $ — $ 126 Accounts receivable, net — 425 38 — 463 Accounts receivable - related party — — 7 (7 ) — Intercompany receivable 3,985 1,356 — (5,341 ) — Inventories — 39 — — 39 Derivative instruments — 5 — — 5 Prepaid expenses and other 1 59 — — 60 Total current assets 4,107 1,879 55 (5,348 ) 693 Property and equipment: Oil and natural gas properties, at cost, full cost method of accounting — 21,434 1,798 (3 ) 23,229 Midstream assets — 762 — — 762 Other property, equipment and land — 145 6 — 151 Accumulated depletion, depreciation, amortization and impairment — (2,812 ) (264 ) (19 ) (3,095 ) Net property and equipment — 19,529 1,540 (22 ) 21,047 Equity method investments — 150 — — 150 Investment in subsidiaries 12,221 123 — (12,344 ) — Deferred tax asset — — 150 — 150 Investment in real estate, net — 114 — — 114 Other assets — 92 22 — 114 Total assets $ 16,328 $ 21,887 $ 1,767 $ (17,714 ) $ 22,268 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 180 $ — $ — $ 180 Intercompany payable 81 5,267 — (5,348 ) — Accrued capital expenditures — 485 — — 485 Other accrued liabilities 39 196 3 — 238 Revenues and royalties payable — 151 — — 151 Derivative instruments — 58 — — 58 Total current liabilities 120 6,337 3 (5,348 ) 1,112 Long-term debt 2,036 2,477 157 — 4,670 Derivative instruments — 16 — — 16 Asset retirement obligations — 140 — — 140 Deferred income taxes 399 1,403 — — 1,802 Other long-term liabilities — 14 — — 14 Total liabilities 2,555 10,387 160 (5,348 ) 7,754 Commitments and contingencies Stockholders’ equity 13,773 11,500 819 (12,319 ) 13,773 Non-controlling interest — — 788 (47 ) 741 Total equity 13,773 11,500 1,607 (12,366 ) 14,514 Total liabilities and equity $ 16,328 $ 21,887 $ 1,767 $ (17,714 ) $ 22,268 Condensed Consolidated Balance Sheet December 31, 2018 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 84 $ 108 $ 23 $ — $ 215 Accounts receivable — 354 38 — 392 Accounts receivable - related party — — 3 (3 ) — Intercompany receivable 4,469 201 — (4,670 ) — Inventories — 37 — — 37 Derivative instruments — 231 — — 231 Prepaid expenses and other 3 47 — — 50 Total current assets 4,556 978 64 (4,673 ) 925 Property and equipment: Oil and natural gas properties, at cost, full cost method of accounting — 20,586 1,717 (4 ) 22,299 Midstream assets — 700 — — 700 Other property, equipment and land — 141 6 — 147 Accumulated depletion, depreciation, amortization and impairment — (2,514 ) (248 ) (12 ) (2,774 ) Net property and equipment — 18,913 1,475 (16 ) 20,372 Equity method investments — 1 — — 1 Investment in subsidiaries 11,576 112 — (11,688 ) — Investment in real estate, net — 116 — — 116 Deferred tax asset — — 97 — 97 Other assets — 67 18 — 85 Total assets $ 16,132 $ 20,187 $ 1,654 $ (16,377 ) $ 21,596 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 128 $ — $ — $ 128 Intercompany payable — 4,673 — (4,673 ) — Accrued capital expenditures — 495 — — 495 Other accrued liabilities 14 233 6 — 253 Revenues and royalties payable — 143 — — 143 Total current liabilities 14 5,672 6 (4,673 ) 1,019 Long-term debt 2,036 2,017 411 — 4,464 Derivative instruments — 15 — — 15 Asset retirement obligations — 136 — — 136 Deferred income taxes 382 1,403 — — 1,785 Other long-term liabilities — 10 — — 10 Total liabilities 2,432 9,253 417 (4,673 ) 7,429 Commitments and contingencies Stockholders’ equity 13,700 10,934 542 (11,476 ) 13,700 Non-controlling interest — — 695 (228 ) 467 Total equity 13,700 10,934 1,237 (11,704 ) 14,167 Total liabilities and equity $ 16,132 $ 20,187 $ 1,654 $ (16,377 ) $ 21,596
Condensed Consolidated Statement of Operations	Condensed Consolidated Statement of Operations Three Months Ended March 31, 2019 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 691 $ — $ 52 $ 743 Natural gas sales — 25 — 4 29 Natural gas liquid sales — 66 — 4 70 Royalty income — — 60 (60 ) — Lease bonus — — 1 — 1 Midstream services — 19 — — 19 Other operating income — 2 — — 2 Total revenues — 803 61 — 864 Costs and expenses: Lease operating expenses — 109 — — 109 Production and ad valorem taxes — 51 4 — 55 Gathering and transportation — 12 — — 12 Midstream services — 17 — — 17 Depreciation, depletion and amortization — 300 16 6 322 General and administrative expenses 15 11 1 — 27 Asset retirement obligation accretion — 2 — — 2 Other operating expense — 1 — — 1 Total costs and expenses 15 503 21 6 545 Income (loss) from operations (15 ) 300 40 (6 ) 319 Other income (expense) Interest expense, net (10 ) (30 ) (6 ) — (46 ) Other income (expense), net — 1 — — 1 Loss on derivative instruments, net — (268 ) — — (268 ) Gain on revaluation of investment — — 4 — 4 Total other expense, net (10 ) (297 ) (2 ) — (309 ) Income (loss) before income taxes (25 ) 3 38 (6 ) 10 Provision for income taxes 2 — (35 ) — (33 ) Net income (loss) (27 ) 3 73 (6 ) 43 Net income attributable to non-controlling interest — — 40 (7 ) 33 Net income (loss) attributable to Diamondback Energy, Inc. $ (27 ) $ 3 $ 33 $ 1 $ 10 Condensed Consolidated Statement of Operations Three Months Ended March 31, 2018 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 364 $ — $ 55 $ 419 Natural gas sales — 12 — 2 14 Natural gas liquid sales — 29 — 4 33 Royalty income — — 62 (62 ) — Midstream services — 11 — — 11 Other operating income — 2 — — 2 Total revenues — 418 62 (1 ) 479 Costs and expenses: Lease operating expenses — 37 — — 37 Production and ad valorem taxes — 23 4 — 27 Gathering and transportation — 4 — — 4 Midstream services — 11 — — 11 Depreciation, depletion and amortization — 100 12 3 115 General and administrative expenses 7 7 2 — 16 Asset retirement obligation accretion — 1 — — 1 Other operating expense — 1 — — 1 Total costs and expenses 7 184 18 3 212 Income (loss) from operations (7 ) 234 44 (4 ) 267 Other income (expense) Interest expense, net (9 ) (3 ) (2 ) — (14 ) Other income (expense), net — 3 — — 3 Loss on derivative instruments, net — (32 ) — — (32 ) Gain on revaluation of investment — — 1 — 1 Total other expense, net (9 ) (32 ) (1 ) — (42 ) Income (loss) before income taxes (16 ) 202 43 (4 ) 225 Provision for income taxes 47 — — — 47 Net income (loss) (63 ) 202 43 (4 ) 178 Net income attributable to non-controlling interest — — — 15 15 Net income (loss) attributable to Diamondback Energy, Inc. $ (63 ) $ 202 $ 43 $ (19 ) $ 163
Condensed Consolidated Statement of Cash Flows	Condensed Consolidated Statement of Cash Flows Three Months Ended March 31, 2019 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ 16 $ 316 $ 45 $ — $ 377 Cash flows from investing activities: Additions to oil and natural gas properties — (569 ) — — (569 ) Additions to midstream assets — (58 ) — — (58 ) Purchase of other property, equipment and land — (4 ) — — (4 ) Acquisition of leasehold interests — (75 ) — — (75 ) Acquisition of mineral interests — — (82 ) — (82 ) Equity investments — (149 ) — — (149 ) Net cash used in investing activities — (855 ) (82 ) — (937 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 424 60 — 484 Repayment under credit facility — — (314 ) — (314 ) Proceeds from joint venture — 23 — — 23 Debt issuance costs — (3 ) — — (3 ) Proceeds from public offerings — — 341 — 341 Distributions from subsidiary 37 — — (37 ) — Dividends to stockholders (21 ) — — — (21 ) Repurchased for tax withholdings (13 ) — — — (13 ) Distributions to non-controlling interest — — (63 ) 37 (26 ) Intercompany transfers 18 (18 ) — — — Net cash provided by financing activities 21 426 24 — 471 Net increase (decrease) in cash and cash equivalents 37 (113 ) (13 ) — (89 ) Cash and cash equivalents at beginning of period 84 108 23 — 215 Cash and cash equivalents at end of period $ 121 $ (5 ) $ 10 $ — $ 126 Condensed Consolidated Statement of Cash Flows Three Months Ended March 31, 2018 (in millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ 27 $ 263 $ 49 $ — $ 339 Cash flows from investing activities: Additions to oil and natural gas properties — (280 ) — — (280 ) Additions to midstream assets — (38 ) — — (38 ) Purchase of other property, equipment and land — (2 ) — — (2 ) Acquisition of leasehold interests — (16 ) — — (16 ) Acquisition of mineral interests — — (150 ) — (150 ) Funds held in escrow — 11 — — 11 Intercompany transfers (87 ) 87 — — — Investment in real estate — (110 ) — — (110 ) Net cash used in investing activities (87 ) (348 ) (150 ) — (585 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 77 147 — 224 Repayment under credit facility — (308 ) — — (308 ) Proceeds from senior notes 312 — — — 312 Debt issuance costs (3 ) — — — (3 ) Distributions from subsidiary 33 — — (33 ) — Distributions to non-controlling interest — — (52 ) 33 (19 ) Intercompany transfers (308 ) 308 — — — Net cash provided by financing activities 34 77 95 — 206 Net increase (decrease) in cash and cash equivalents (26 ) (8 ) (6 ) — (40 ) Cash and cash equivalents at beginning of period 54 34 24 — 112 Cash and cash equivalents at end of period $ 28 $ 26 $ 18 $ — $ 72

Description of the Business a_2

Description of the Business and Basis of Presentation (Details)	Mar. 31, 2019
Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP (percentage)	54.00%

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018
Investment [Line Items]
Cumulative effect due to the impact of adoption of ASU 2016.01			$ 16
Operating Lease, Right-of-Use Asset	$ 26	$ 13
Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Investment [Line Items]
Cumulative effect due to the impact of adoption of ASU 2016.01			$ 19

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)ashares	Mar. 31, 2018USD ($)$ / shares	Nov. 29, 2018fraction_per_share$ / shares
Business Acquisition [Line Items]
Investment in real estate	$ 0		$ 110
Energen Corporation Acquisition [Member]
Business Acquisition [Line Items]
Tier One Acres to be Acquired | a		273,000
Combined Net Acreage After Close of Pending Acquisition | a		394,000
Common Stock, Conversion Basis | fraction_per_share				0.6442
Number of shares issued to acquire leasehold interests and related assets | shares		62.8
Business Acquisition, Share Price | $ / shares				$ 112
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	7,136	$ 7,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	349
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Asset Retirement Obligation	105
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt	1,099
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities	17
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	1,403
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	7
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	2,980
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	305
Business combination assets acquired oil and gas properties	9,283
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Midstream Assets	263
Business combination assets acquired investment in real estate	11
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	58
Business combination asset acquired postretirement benefit plan	3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets	76
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	12
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	$ 10,116
Business Acquisition, Pro Forma Revenue			838
Business Acquisition, Pro Forma Income from Operations			418
Business Acquisition, Pro Forma Net Income			$ 268
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares			$ 1.66
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares			$ 1.65

Viper Energy Partners LP (Detai

Viper Energy Partners LP (Details) - USD ($)	Mar. 01, 2019	Jul. 31, 2018	Jun. 30, 2018	Mar. 31, 2019	Mar. 31, 2018	May 10, 2018
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Period Increase (Decrease)				$ 74,000,000
General Partners' Contributed Capital						$ 1,000,000
Limited Partners' Contributed Capital						$ 1,000,000
Limited partners capital account, percentage of distribution						8.00%
Number of Class B Units Converted			731,500
Partners' Capital Account, Units, Converted			731,500
Limited Partners' Capital Account, Distribution Amount			$ 10,000
Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP (percentage)				54.00%
Parent Company [Member]
Noncontrolling Interest [Line Items]
Units of Partnership Interest, Amount						73,150,000
Other Partners' Capital						73,150,000
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest		59.00%	64.00%
Partnership Agreement [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Revenue from Related Parties				$ 1,000,000	$ 1,000,000
General Partner [Member]
Noncontrolling Interest [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		41.00%	36.00%
Follow-on Public Offering [Member] | Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP (percentage)	54.00%
Sale of Stock, Number of Shares Issued in Transaction	10,925,000
Sale of Stock, Consideration Received on Transaction	$ 341,000,000
Over-Allotment Option [Member] | Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	1,425,000

Real Estate Assets (Details)

Real Estate Assets (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Real Estate [Line Items]
Buildings	$ 103	$ 103
Tenant improvements	4	4
Land	1	1
Land improvements	1	1
Total real estate assets	109	109
Less: accumulated depreciation	(5)	(4)
Total investment in land and buildings, net	104	105
In-place lease intangibles	11	11
Less: accumulated amortization	(4)	(3)
In-place lease intangibles, net	7	8
Above-market lease intangibles	4	4
Less: accumulated amortization	(1)	(1)
Above-market lease intangibles, net	3	3
Total intangible lease assets, net	$ 10	$ 11
Leases, Acquired-in-Place [Member]
Real Estate [Line Items]
Finite-Lived Intangible Asset, Useful Life	45 months
Above Market Leases [Member]
Real Estate [Line Items]
Finite-Lived Intangible Asset, Useful Life	45 months
Building [Member]
Real Estate [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	30 years
Leasehold Improvements [Member]
Real Estate [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	15 years
Land Improvements [Member]
Real Estate [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	15 years

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and natural gas properties:
Not subject to depletion	$ 9,646		$ 9,670
Gross oil and natural gas properties	23,229		22,299
Accumulated depletion and depreciation	(3,095)		(2,774)
Midstream assets	762		700
Other property, equipment and land	151		147
Net property and equipment	21,047		20,372
Capitalized internal costs	13	$ 7
Exploration costs or development costs not subject to depletion	91		68
Capitalized interest not subject to depletion	$ 71		55
Minimum [Member]
Oil and natural gas properties:
Timing of inclusion of costs in amortization calculation	3 years
Maximum [Member]
Oil and natural gas properties:
Timing of inclusion of costs in amortization calculation	5 years
Oil and Gas Properties [Member]
Oil and natural gas properties:
Subject to depletion	$ 13,583		12,629
Not subject to depletion	9,646		9,670
Gross oil and natural gas properties	23,229		22,299
Accumulated depletion and depreciation	(1,907)		(1,599)
Accumulated impairment	(1,144)		(1,144)
Oil and natural gas properties, net	20,178		19,556
Balance of costs not subject to depletion:	186		6,142	$ 2,473	$ 687	$ 158
Other Property and Equipment, Net [Member]
Oil and natural gas properties:
Accumulated depletion and depreciation	(44)		(31)
Other property, equipment and land	$ 151		$ 147

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Changes in ARO liability
Asset retirement obligations, beginning of period	$ 136	$ 21
Additional liabilities incurred	1	1
Liabilities acquired	3	0
Liabilities settled	(2)	(1)
Asset retirement obligation accretion	2	1
Asset retirement obligations, end of period	140	22
Less current portion	0	1
Asset retirement obligations - long-term	$ 140	$ 21	$ 136

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 29, 2019	Feb. 15, 2019	Feb. 01, 2019	Dec. 31, 2018	Oct. 28, 2016	Oct. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Other than Temporary Impairment	$ 0	$ 0
Income from equity method investments	0	2,000,000
Equity method investments	150,000,000					$ 1,000,000
HMW Fluid Management LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage								25.00%
Income from equity method investments	0	$ 2,000,000
EPIC Crude Holdings, LP [Domain]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage					10.00%
Equity method investments	35,000,000
Gray Oak Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				10.00%
Income from equity method investments	50,000
Equity method investments	$ 115,000,000
Gray Oak Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment promissory note			$ 123,000,000
Debt Instrument, Interest Rate, Stated Percentage							2.52%

Debt - Long-term Debt (Details)

Debt - Long-term Debt (Details) - USD ($) $ in Millions		Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017	Dec. 20, 2016	Oct. 28, 2016
Debt Instrument [Line Items]
Unamortized debt issuance costs		$ (24)	$ (27)
Unamortized premium cost		10	10
Long-term Debt		4,670	4,464
4.625% Notes due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[1]	$ 399	$ 400
Debt Instrument, Interest Rate, Stated Percentage		4.625%	4.625%
7.32% Medium Term Series A due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[1]	$ 21	$ 20
Debt Instrument, Interest Rate, Stated Percentage		7.32%	7.32%
Senior Unsecured Notes due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,250	$ 1,250
Debt Instrument, Interest Rate, Stated Percentage		4.75%	4.75%	4.75%	4.75%		4.75%
Senior Unsecured Notes due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 800	$ 800
Debt Instrument, Interest Rate, Stated Percentage		5.375%	5.375%	5.375%	5.375%	5.375%
7.35% Medium Term Notes Series A [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[1]	$ 11	$ 10
Debt Instrument, Interest Rate, Stated Percentage		7.35%	7.35%
7.125% Medium Term Notes Series B [Member] [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[1]	$ 109	$ 100
Debt Instrument, Interest Rate, Stated Percentage		7.125%	7.125%
DrillCo Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 23	$ 0
Company Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		1,914	1,490
Partnership Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 157	$ 411
[1]	At the effective time of the Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of these notes (the “Energen Notes”).

Debt - Senior Notes (Details)

Debt - Senior Notes (Details) - USD ($) $ in Millions	Sep. 18, 2018	Jan. 29, 2018	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017	Dec. 20, 2016	Oct. 28, 2016
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt			$ 0	$ 312
Senior Unsecured Notes due 2024 [Member]
Debt Instrument [Line Items]
Aggregate principal amount									$ 500
Debt Instrument, Interest Rate, Stated Percentage			4.75%		4.75%	4.75%	4.75%		4.75%
Debt Instrument, Redemption Price, Percentage			100.00%
Long-term Debt, Gross			$ 1,250		$ 1,250
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			103.563%
Debt Instrument, Redemption Period, Start Date			Nov. 1, 2019
Debt Instrument, Redemption Period, End Date			Oct. 31, 2020
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			102.375%
Debt Instrument, Redemption Period, Start Date			Nov. 1, 2020
Debt Instrument, Redemption Period, End Date			Oct. 31, 2021
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			101.188%
Debt Instrument, Redemption Period, Start Date			Nov. 1, 2021
Debt Instrument, Redemption Period, End Date			Oct. 31, 2022
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Four [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			100.00%
Debt Instrument, Redemption Period, Start Date			Nov. 1, 2022
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			104.75%
Debt Instrument, Redemption Period, Start Date			Oct. 28, 2016
Debt Instrument, Redemption Period, End Date			Oct. 31, 2019
Senior Unsecured Additional Notes due 2024 [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 750
Debt Instrument, Interest Rate, Stated Percentage	4.75%
Proceeds from Issuance of Senior Long-term Debt	$ 741
Senior Unsecured Notes due 2025 [Member]
Debt Instrument [Line Items]
Aggregate principal amount								$ 500
Debt Instrument, Interest Rate, Stated Percentage			5.375%		5.375%	5.375%	5.375%	5.375%
Debt Instrument, Redemption Price, Percentage			100.00%
Long-term Debt, Gross			$ 800		$ 800
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			104.031%
Debt Instrument, Redemption Period, Start Date			May 31, 2020
Debt Instrument, Redemption Period, End Date			May 30, 2021
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			102.688%
Debt Instrument, Redemption Period, Start Date			May 31, 2021
Debt Instrument, Redemption Period, End Date			May 30, 2022
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			101.344%
Debt Instrument, Redemption Period, Start Date			May 31, 2022
Debt Instrument, Redemption Period, End Date			May 30, 2023
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Four [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			100.00%
Debt Instrument, Redemption Period, Start Date			May 31, 2023
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			105.375%
Debt Instrument, Redemption Period, Start Date			Dec. 20, 2016
Debt Instrument, Redemption Period, End Date			May 30, 2020
Senior Unsecured Additional Notes due 2025 [Member]
Debt Instrument [Line Items]
Aggregate principal amount		$ 300
Debt Instrument, Interest Rate, Stated Percentage		5.375%
Proceeds from Issuance of Senior Long-term Debt		$ 308
Maximum [Member] | Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument Percentage Eligible for Redemption			35.00%
Maximum [Member] | Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument Percentage Eligible for Redemption			35.00%

Debt Energen Notes (Details)

Debt Energen Notes (Details) - Energen [Member] $ in Millions	Nov. 29, 2018USD ($)
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 530
Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 400
Debt Instrument, Interest Rate, Stated Percentage	4.625%
Medium-term Notes, Series B [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 100
Debt Instrument, Interest Rate, Stated Percentage	7.125%
Medium-term Notes, Series A, Due July 28, 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 20
Debt Instrument, Interest Rate, Stated Percentage	7.32%
Medium-term Notes, Series A, Due July 28, 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 10
Debt Instrument, Interest Rate, Stated Percentage	7.35%

Debt - Credit Facility - Wells

Debt - Credit Facility - Wells Fargo Bank (Details) - Company Credit Facility [Member] $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)redetermindation	Mar. 25, 2019USD ($)	Dec. 31, 2018USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 5,000
Number of interim redeterminations that may be requested | redetermindation	2
Period of redeterminations (in months)	12 months
Current borrowing base	$ 3,000
Line of Credit Facility, Elected Borrowing Base	3,000	$ 2,000
Long-term Debt, Gross	1,914		$ 1,490
Remaining Borrowing Capacity	$ 1,000
Minimum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Maximum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.50%
Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.50%
LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.00%
LIBOR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.25%
LIBOR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	2.25%
Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.25%
Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.25%

Debt - Partnership Credit Facil

Debt - Partnership Credit Facility - Wells Fargo Bank (Details) - Partnership Credit Facility [Member] $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)redetermindation	Dec. 31, 2018USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000
Number of interim redeterminations that may be requested | redetermindation	3
Period of redeterminations (in months)	12 months
Current borrowing base	$ 555
Long-term Debt, Gross	157	$ 411
Remaining Borrowing Capacity	$ 398
Minimum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Maximum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.50%
Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.50%
LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.00%
LIBOR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.75%
LIBOR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	2.75%
Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.75%
Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.75%

Debt - Financial Covenant Table

Debt - Financial Covenant Table (Details) $ in Millions	Mar. 31, 2019USD ($)
Company Credit Facility [Member]
Line of Credit Facility [Line Items]
Financial covenant, reduction of borrowing base (percentage)	25.00%
Company Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX	4
Company Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1
Partnership Credit Facility [Member]
Line of Credit Facility [Line Items]
Financial covenant, maximum issuance of unsecured debt	$ 400
Financial covenant, reduction of borrowing base (percentage)	25.00%
Partnership Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX	4
Partnership Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1

Debt - Alliance with Obsidian R

Debt - Alliance with Obsidian Resources, L.L.C. (Details) - DrillCo Agreement [Member] $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)
Alliance with Obsidian Resources, L.L.C. [Line Items]
Maximum Funding Amount Through Joint Venture	$ 300
Amounts received from joint venture	$ 18
Wells drilled and completed under joint venture agreement	6

Capital Stock and Earnings Pe_3

Capital Stock and Earnings Per Share - Capital Stock (Details) - Viper Energy Partners LP [Member] - USD ($) $ in Millions	Mar. 01, 2019	Mar. 31, 2019
Class of Stock [Line Items]
Interest in Viper Energy Partners LP (percentage)		54.00%
Follow-on Public Offering [Member]
Class of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	10,925,000
Interest in Viper Energy Partners LP (percentage)	54.00%
Sale of Stock, Consideration Received on Transaction	$ 341
Over-Allotment Option [Member]
Class of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	1,425,000

Capital Stock and Earnings Pe_4

Capital Stock and Earnings Per Share - Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Basic:
Net income attributable to common stock	$ 10	$ 163
Basic weighted average common units outstanding	164,852	98,555
Basic net income attributable to common stock	$ 0.06	$ 1.65
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable (in shares)	209	214
Diluted:
Diluted weighted average common shares outstanding	165,061	98,769
Diluted net income attributable to common stock	$ 0.06	$ 1.65
Antidilutive securities excluded from earnings per share (in shares)	31	0

Equity-Based Compensation - Sch

Equity-Based Compensation - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$ 6	$ 3
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
General and administrative expenses	$ 14	$ 8

Equity-Based Compensation - Res

Equity-Based Compensation - Restricted Stock Units (Details) - Equity Plan [Member] - Restricted Stock Units (RSUs) [Member] $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)$ / sharesshares	Mar. 31, 2018USD ($)
Awards & Units (in shares)
Unvested at December 31, 2018 | shares	324,224
Granted | shares	435,049
Vested | shares	(119,477)
Forfeited | shares	(9,652)
Unvested at March 31, 2019 | shares	630,144
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at December 31, 2018 | $ / shares	$ 116.01
Granted | $ / shares	107.30
Vested | $ / shares	109.05
Forfeited | $ / shares	112.27
Unvested at March 31, 2019 | $ / shares	$ 111.37
Aggregate fair value of share-based awards that vested | $	$ 13	$ 9
Unrecognized compensation cost related to unvested awards | $	$ 55
Unrecognized compensation cost, period of recognition (in years)	1 year 3 months 18 days

Equity-Based Compensation - Per

Equity-Based Compensation - Performance Restricted Stock Activity (Details) - Equity Plan [Member] - Performance Shares [Member] $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended
	Mar. 31, 2019USD ($)$ / sharesshares		Mar. 31, 2019USD ($)$ / sharesshares
Awards & Units (in shares)
Unvested at December 31, 2018			196,203
Granted			356,227
Vested			(123,546)
Unvested at March 31, 2019	428,884	[1]	428,884	[1]
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at December 31, 2018 | $ / shares			$ 169.76
Granted | $ / shares			131.30
Vested | $ / shares			121.41
Unvested at March 31, 2019 | $ / shares	$ 151.74		$ 151.74
Share Based Compensation Arrangement by Share Based Payment Maximum Award Potential	857,768		857,768
Unrecognized compensation cost related to unvested awards | $	$ 47		$ 47
Unrecognized compensation cost, period of recognition (in years)			1 year 4 months 24 days
Three-Year [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period	3 years
Awards & Units (in shares)
Granted	199,723
Weighted Average Grant-Date Fair Value (in dollars per share)
Granted | $ / shares	$ 137.22
Three-Year [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be awarded, percent of initial awards received	0.00%
Three-Year [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be awarded, percent of initial awards received	200.00%
Five-Year [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period	5 years
Awards & Units (in shares)
Granted	32,958
Weighted Average Grant-Date Fair Value (in dollars per share)
Granted | $ / shares	$ 132.48
Five-Year [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be awarded, percent of initial awards received	0.00%
Five-Year [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be awarded, percent of initial awards received	200.00%
[1]	A maximum of 857,768

Equity-Based Compensation - Val

Equity-Based Compensation - Valuation Assumptions (Details) - Equity Plan [Member] - Performance Shares [Member] - $ / shares	1 Months Ended	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted		$ 131.30
Risk-free rate (percentage)	2.55%
Company volatility (percentage)	35.00%
Five-Year [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted	$ 132.48

Equity-Based Compensation - Sto

Equity-Based Compensation - Stock Appreciation Rights (Details) - Equity Plan [Member] - Stock Appreciation Rights (SARs) [Member]	3 Months Ended
	Mar. 31, 2019$ / sharesshares
Awards & Units (in shares)
Unvested at December 31, 2018 | shares	57,721
Granted | shares	(7,111)
Forfeited | shares	(8,691)
Unvested at March 31, 2019 | shares	41,919
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at December 31, 2018 | $ / shares	$ 22.12
Granted | $ / shares	20.18
Forfeited | $ / shares	23.29
Unvested at March 31, 2019 | $ / shares	$ 24.74

Equity-Based Compensation - S_2

Equity-Based Compensation - Stock Options (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Options (in shares)
Outstanding at December 31, 2018	332,387
Granted	0
Outstanding at March 31, 2019	332,387
\Weighted Average Exercise Price (in dollars per share)
Accounts receivable - related party	$ 0	$ 0
Outstanding at December 31, 2018	$ 95.04
Granted	0
Outstanding at March 31, 2019	$ 95.04
Weighted average remaining contractual term	2 years 5 months 26 days
Intrinsic value of options outstanding	$ 14
Vested and Expected to vest at March 31, 2019	332,387
Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$ 95.04
Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term	2 years 5 months 26 days
Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 14
Options, Vested and Expected to Vest, Exercisable, Number	332,387
Options, Vested and Expected to Vest, Exercisable, Weighted Average Exercise Price	$ 95.04
Options, Vested and Expected to Vest, Exercisable, Weighted Average Remaining Contractual Term	2 years 5 months 26 days
Options, Vested and Expected to Vest, Exercisable, Aggregate Intrinsic Value	$ 14

Equity-Based Compensation - Pha

Equity-Based Compensation - Phantom Units (Details) - Viper Energy Partners LP Long Term Incentive Plan [Member] - Phantom Share Units (PSUs) [Member] - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2019
Awards & Units (in shares)
Unvested at December 31, 2018	125,053
Granted	11,001
Vested	(60,133)
Unvested at March 31, 2019	75,921
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at December 31, 2018	$ 23.44
Granted	33.30
Vested	21.38
Unvested at March 31, 2019	$ 26.51
Aggregate fair value of share-based awards that vested	$ 1
Unrecognized compensation cost related to unvested awards	$ 2
Unrecognized compensation cost, period of recognition (in years)	11 months 26 days

Related Party Transactions - Re

Related Party Transactions - Related Party Transactions (Details)	Jun. 23, 2014USD ($)	Mar. 31, 2019USD ($)	Mar. 31, 2018USD ($)
Parent Company [Member]
Related Party Transaction [Line Items]
Payments for Operating Activities		$ 198	$ 0
Number of leases extended		1
Average price per acre		$ 125
Revenue from related parties on new leases		$ 3,101
Number of new leases		2
Average price per acre on new leases		$ 14,766
Viper Energy Partners LP [Member] | Wexford [Member] | Advisory Services Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Annual Fee for Advisory Services with Related Party	$ 500,000
Payments for Operating Activities		$ 0	$ 0

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Investments, Owned, Federal Income Tax Note [Line Items]
Effective income tax rate	(301.70%)	20.90%
Discrete income tax benefit recorded during the period related to equity-based compensation	$ 1
Discrete income tax benefit related to deferred taxes recorded during the period	$ 35

Derivatives - Open Derivative P

Derivatives - Open Derivative Positions (Details)	3 Months Ended
	Mar. 31, 2019MMBTU$ / bbl$ / MMBTUbbl
WTI Cushing Oil Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	7,758,000
Fixed Swap Price (in dollars per bbl)	61.10
WTI Cushing Oil Swaps 2020 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Swap Price (in dollars per bbl)	0
WTI Magellan East Houston Oil Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,008,000
Fixed Swap Price (in dollars per bbl)	69.27
WTI Magellan East Houston Oil Swaps 2020 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Swap Price (in dollars per bbl)	0
BRENT Oil Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,375,000
Fixed Swap Price (in dollars per bbl)	67.22
BRENT Oil Swaps 2020 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Swap Price (in dollars per bbl)	0
WTI Cushing Oil Basis Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	12,966,000
Fixed Swap Price (in dollars per bbl)	(5.42)
WTI Cushing Oil Basis Swaps 2020 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	15,120,000
Fixed Swap Price (in dollars per bbl)	(1.21)
Natural Gas Swaps 2019 - Henry Hub [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	19,250,000
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	3.06
Natural Gas Swaps 2020 - Henry Hub [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	0
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	0
Natural Gas Basis swaps - Waha Hub 2019 [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	19,250,000
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	(1.56)
Natural Gas Basis Swaps - Waha Hub 2020 [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	0
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	0
Natural Gas Liquid Swaps - Mont Belvieu 2019 [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	2,070,000
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	27.30
Natural Gas Liquid Swaps - Mont Belvieu 2020 [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	0
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	0
2019 Three-Way Collars - WTI Cushing [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	5,230,000
Short put price (per Bbl)	37.51
Floor price (per Bbl)	47.51
Ceiling price (per Bbl)	63.05
2019 Three-Way Collars - BRENT [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,648,000
Short put price (per Bbl)	53.88
Floor price (per Bbl)	63.88
Ceiling price (per Bbl)	80.09
2019 Three-Way Collars - WTI Magellan East Houston [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,284,000
Short put price (per Bbl)	52.13
Floor price (per Bbl)	62.13
Ceiling price (per Bbl)	69.38
2020 Three-Way Collars - BRENT [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	3,660,000
Short put price (per Bbl)	50
Floor price (per Bbl)	60
Ceiling price (per Bbl)	74.63
2020 Three-Way Collars - WTI Magellan East Houston [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	2,190,000
Short put price (per Bbl)	50
Floor price (per Bbl)	60
Ceiling price (per Bbl)	66.90

Derivatives - Offsetting Deriva

Derivatives - Offsetting Derivative Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross amounts of assets presented in the Consolidated Balance Sheet	$ 5	$ 231
Net amounts of assets presented in the Consolidated Balance Sheet	5	231
Gross amounts of liabilities presented in the Consolidated Balance Sheet	74	15
Net amounts of liabilities presented in the Consolidated Balance Sheet	$ 74	$ 15

Derivatives - Balance Sheet Loc

Derivatives - Balance Sheet Location (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current assets: derivative instruments	$ 5	$ 231
Noncurrent assets: derivative instruments	0	0
Total assets	5	231
Current liabilities: derivative instruments	58	0
Noncurrent liabilities: derivative instruments	16	15
Total liabilities	$ 74	$ 15

Derivatives - Gains and Losses

Derivatives - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of open non-hedge derivative instruments	$ (285)	$ 0
Gain (loss) on settlement of non-hedge derivative instruments	17	(32)
Loss on derivative instruments	$ (268)	$ (32)

Fair Value Measurements - Recur

Fair Value Measurements - Recurring Measurements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Assets:
Impact of adoption of ASU 2016-01, net of tax		$ (16)
Gain on revaluation of investment	$ 4	1
Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Fixed price swaps	0		$ 0
Equity Method Investments, Fair Value Disclosure	18		14
Impact of adoption of ASU 2016-01, net of tax		(19)
Gain on revaluation of investment	4	1
Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Fixed price swaps	0		0
Fair Value, Net Asset (Liability)	69		216
Equity Method Investments, Fair Value Disclosure	0		0
Recurring [Member] | Significant Unobservable Inputs Level 3 [Member]
Assets:
Fixed price swaps	0		0
Equity Method Investments, Fair Value Disclosure	0		0
Other Noncurrent Assets [Member] | Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Equity Method Investments, Fair Value Disclosure	$ 18	$ 16	$ 14	$ 34

Fair Value Measurements - Nonre

Fair Value Measurements - Nonrecurring Measurements (Details) - USD ($) $ in Millions		Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017	Dec. 20, 2016	Oct. 28, 2016
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Long-term Debt		$ 4,670	$ 4,464
4.625% Notes due 2021 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage		4.625%	4.625%
7.32% Medium Term Series A due 2022 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage		7.32%	7.32%
Senior Unsecured Notes due 2024 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage		4.75%	4.75%	4.75%	4.75%		4.75%
Senior Unsecured Notes due 2025 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage		5.375%	5.375%	5.375%	5.375%	5.375%
7.35% Medium Term Notes Series A [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage		7.35%	7.35%
7.125% Medium Term Notes Series B [Member] [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage		7.125%	7.125%
Reported Value Measurement [Member] | Company Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility		$ 1,914	$ 1,490
Reported Value Measurement [Member] | 4.625% Notes due 2021 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	399	400
Reported Value Measurement [Member] | 7.32% Medium Term Series A due 2022 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	21	20
Reported Value Measurement [Member] | Senior Unsecured Notes due 2024 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes		1,250	1,250
Reported Value Measurement [Member] | Senior Unsecured Notes due 2025 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes		800	800
Reported Value Measurement [Member] | 7.35% Medium Term Notes Series A [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	11	10
Reported Value Measurement [Member] | 7.125% Medium Term Notes Series B [Member] [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	109	100
Reported Value Measurement [Member] | Partnership Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility		157	411
Reported Value Measurement [Member] | DrillCo Agreement [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Long-term Debt		23	0
Estimate of Fair Value Measurement [Member] | 4.625% Notes due 2021 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	404	393
Estimate of Fair Value Measurement [Member] | 7.32% Medium Term Series A due 2022 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	22	21
Estimate of Fair Value Measurement [Member] | 7.35% Medium Term Notes Series A [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	11	11
Estimate of Fair Value Measurement [Member] | 7.125% Medium Term Notes Series B [Member] [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	[1]	110	102
Estimate of Fair Value Measurement [Member] | DrillCo Agreement [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Long-term Debt, Fair Value		23	0
Fair Value, Inputs, Level 1 [Member] | Estimate of Fair Value Measurement [Member] | Senior Unsecured Notes due 2024 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes		1,283	1,204
Fair Value, Inputs, Level 1 [Member] | Estimate of Fair Value Measurement [Member] | Senior Unsecured Notes due 2025 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes		838	782
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member] | Company Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility		1,914	1,490
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member] | Partnership Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility		$ 157	$ 411
[1]	At the effective time of the Energen Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of the Energen Notes. These notes were marked to fair value with the excess being amortized.

Leases (Details)

Leases (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 26	$ 13
Operating Lease, Cost	4
Additional amount of operating lease right of use asset recorded	8
Operating Lease, Payments	5
Operating Lease, Liability	26
Operating Lease, Liability, Current	$ 21
Operating Lease, Weighted Average Remaining Lease Term	1 year 4 months 24 days
Operating Lease, Weighted Average Discount Rate, Percent	8.40%
2019 (April - December)	$ 22
2020	4
2021	1
2022	0
2023	0
Thereafter	0
Total lease payments	27
Less: interest	$ 1

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Millions	May 07, 2019USD ($)a$ / bbl	May 07, 2019USD ($)$ / bblbbl	Jun. 30, 2019$ / shares	Mar. 31, 2019$ / shares$ / bblbbl	Mar. 31, 2018$ / shares	May 02, 2019USD ($)
Subsequent Event [Line Items]
Dividends declared per share | $ / shares				$ 0.1875	$ 0.125
2019 Three-Way Collars - BRENT [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				1,648,000
Short put price (per Bbl)				53.88
Floor price (per Bbl)				63.88
Ceiling price (per Bbl)				80.09
WTI Cushing Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				7,758,000
Fixed Swap Price (in dollars per bbl)				61.10
WTI Magellan East Houston Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				1,008,000
Fixed Swap Price (in dollars per bbl)				69.27
BRENT Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				1,375,000
Fixed Swap Price (in dollars per bbl)				67.22
WTI Cushing Oil Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				0
Fixed Swap Price (in dollars per bbl)				0
2019 Three-Way Collars - WTI Magellan East Houston [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				1,284,000
Short put price (per Bbl)				52.13
Floor price (per Bbl)				62.13
Ceiling price (per Bbl)				69.38
WTI Magellan East Houston Oil Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				0
Fixed Swap Price (in dollars per bbl)				0
BRENT Oil Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				0
Fixed Swap Price (in dollars per bbl)				0
2020 Three-Way Collars - BRENT [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				3,660,000
Short put price (per Bbl)				50
Floor price (per Bbl)				60
Ceiling price (per Bbl)				74.63
2020 Three-Way Collars - WTI Magellan East Houston [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl				2,190,000
Short put price (per Bbl)				50
Floor price (per Bbl)				60
Ceiling price (per Bbl)				66.90
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividends declared per share | $ / shares			$ 0.1875
Stock Repurchase Program, Authorized Amount | $	$ 2,000	$ 2,000
Pending divested net acres | a	103,423
Sales price of pending divestitures | $	$ 322
Subsequent Event [Member] | 2019 Three-Way Collars - BRENT [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		368,000
Short put price (per Bbl)	50	50
Floor price (per Bbl)	60	60
Ceiling price (per Bbl)	77.50	77.50
Subsequent Event [Member] | 2020 Three-Way Collars - WTI [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		2,928,000
Short put price (per Bbl)	45	45
Floor price (per Bbl)	55	55
Ceiling price (per Bbl)	67	67
Subsequent Event [Member] | WTI Cushing Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		368,000
Fixed Swap Price (in dollars per bbl)	61.72	61.72
Subsequent Event [Member] | WTI Magellan East Houston Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		828,000
Fixed Swap Price (in dollars per bbl)	65.61	65.61
Subsequent Event [Member] | BRENT Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		368,000
Fixed Swap Price (in dollars per bbl)	69.45	69.45
Subsequent Event [Member] | WTI Cushing Oil Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		2,562,000
Fixed Swap Price (in dollars per bbl)	60.63	60.63
Subsequent Event [Member] | WTI Magellan East Houston Oil Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		1,464,000
Fixed Swap Price (in dollars per bbl)	64.25	64.25
Subsequent Event [Member] | BRENT Oil Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		1,464,000
Fixed Swap Price (in dollars per bbl)	66.24	66.24
Subsequent Event [Member] | 2020 Three-Way Collars - BRENT [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		2,196,000
Short put price (per Bbl)	51.67	51.67
Floor price (per Bbl)	61.67	61.67
Ceiling price (per Bbl)	74.92	74.92
Subsequent Event [Member] | 2020 Three-Way Collars - WTI Magellan East Houston [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		2,928,000
Short put price (per Bbl)	50	50
Floor price (per Bbl)	60	60
Ceiling price (per Bbl)	69.90	69.90
Gray Oak Pipeline [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Amount outstanding under equity method investment promissory note | $						$ 23

Guarantor Financial Statement_2

Guarantor Financial Statements - Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 126	$ 215	$ 72	$ 112
Accounts receivable, net	463	392
Accounts Receivable, Related Parties, Current	0	0
Intercompany receivable	0	0
Inventories	39	37
Derivative instruments	5	231
Other current assets	60	50
Total current assets	693	925
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	23,229	22,299
Midstream assets	762	700
Other property, equipment and land	151	147
Accumulated depletion, depreciation, amortization and impairment	(3,095)	(2,774)
Net property and equipment	21,047	20,372
Equity method investments	150	1
Investment in subsidiaries	0	0
Deferred tax asset	150	97
Investment in real estate, net	114	116
Other assets	114	85
Total assets	22,268	21,596
Current liabilities:
Accounts payable-trade	180	128
Intercompany payable	0	0
Accrued capital expenditures	485	495
Other accrued liabilities	238	253
Revenues and royalties payable	151	143
Derivative instruments	58	0
Total current liabilities	1,112	1,019
Long-term debt	4,670	4,464
Derivative instruments	16	15
Asset retirement obligations	140	136	21
Deferred income taxes	1,802	1,785
Other long-term liabilities	14	10
Total liabilities	7,754	7,429
Commitments and contingencies
Stockholders’ equity	13,773	13,700
Non-controlling interest	741	467
Total equity	14,514	14,167	5,735	5,582
Total liabilities and equity	22,268	21,596
Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0
Accounts Receivable, Related Parties, Current	(7)	(3)
Intercompany receivable	(5,341)	(4,670)
Inventories	0	0
Derivative instruments	0	0
Other current assets	0	0
Total current assets	(5,348)	(4,673)
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	(3)	(4)
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	(19)	(12)
Net property and equipment	(22)	(16)
Equity method investments	0	0
Investment in subsidiaries	(12,344)	(11,688)
Deferred tax asset	0	0
Investment in real estate, net	0	0
Other assets	0	0
Total assets	(17,714)	(16,377)
Current liabilities:
Accounts payable-trade	0	0
Intercompany payable	(5,348)	(4,673)
Accrued capital expenditures	0	0
Other accrued liabilities	0	0
Revenues and royalties payable	0	0
Derivative instruments	0
Total current liabilities	(5,348)	(4,673)
Long-term debt	0	0
Derivative instruments	0	0
Asset retirement obligations	0	0
Deferred income taxes	0	0
Other long-term liabilities	0	0
Total liabilities	(5,348)	(4,673)
Commitments and contingencies
Stockholders’ equity	(12,319)	(11,476)
Non-controlling interest	(47)	(228)
Total equity	(12,366)	(11,704)
Total liabilities and equity	(17,714)	(16,377)
Parent Company [Member] | Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	121	84	28	54
Accounts receivable, net	0	0
Accounts Receivable, Related Parties, Current	0	0
Intercompany receivable	3,985	4,469
Inventories	0	0
Derivative instruments	0	0
Other current assets	1	3
Total current assets	4,107	4,556
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	0	0
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	0	0
Net property and equipment	0	0
Equity method investments	0	0
Investment in subsidiaries	12,221	11,576
Deferred tax asset	0	0
Investment in real estate, net	0	0
Other assets	0	0
Total assets	16,328	16,132
Current liabilities:
Accounts payable-trade	0	0
Intercompany payable	81	0
Accrued capital expenditures	0	0
Other accrued liabilities	39	14
Revenues and royalties payable	0	0
Derivative instruments	0
Total current liabilities	120	14
Long-term debt	2,036	2,036
Derivative instruments	0	0
Asset retirement obligations	0	0
Deferred income taxes	399	382
Other long-term liabilities	0	0
Total liabilities	2,555	2,432
Commitments and contingencies
Stockholders’ equity	13,773	13,700
Non-controlling interest	0	0
Total equity	13,773	13,700
Total liabilities and equity	16,328	16,132
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	(5)	108	26	34
Accounts receivable, net	425	354
Accounts Receivable, Related Parties, Current	0	0
Intercompany receivable	1,356	201
Inventories	39	37
Derivative instruments	5	231
Other current assets	59	47
Total current assets	1,879	978
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	21,434	20,586
Midstream assets	762	700
Other property, equipment and land	145	141
Accumulated depletion, depreciation, amortization and impairment	(2,812)	(2,514)
Net property and equipment	19,529	18,913
Equity method investments	150	1
Investment in subsidiaries	123	112
Deferred tax asset	0	0
Investment in real estate, net	114	116
Other assets	92	67
Total assets	21,887	20,187
Current liabilities:
Accounts payable-trade	180	128
Intercompany payable	5,267	4,673
Accrued capital expenditures	485	495
Other accrued liabilities	196	233
Revenues and royalties payable	151	143
Derivative instruments	58
Total current liabilities	6,337	5,672
Long-term debt	2,477	2,017
Derivative instruments	16	15
Asset retirement obligations	140	136
Deferred income taxes	1,403	1,403
Other long-term liabilities	14	10
Total liabilities	10,387	9,253
Commitments and contingencies
Stockholders’ equity	11,500	10,934
Non-controlling interest	0	0
Total equity	11,500	10,934
Total liabilities and equity	21,887	20,187
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	10	23	$ 18	$ 24
Accounts receivable, net	38	38
Accounts Receivable, Related Parties, Current	7	3
Intercompany receivable	0	0
Inventories	0	0
Derivative instruments	0	0
Other current assets	0	0
Total current assets	55	64
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	1,798	1,717
Midstream assets	0	0
Other property, equipment and land	6	6
Accumulated depletion, depreciation, amortization and impairment	(264)	(248)
Net property and equipment	1,540	1,475
Equity method investments	0	0
Investment in subsidiaries	0	0
Deferred tax asset	150	97
Investment in real estate, net	0	0
Other assets	22	18
Total assets	1,767	1,654
Current liabilities:
Accounts payable-trade	0	0
Intercompany payable	0	0
Accrued capital expenditures	0	0
Other accrued liabilities	3	6
Revenues and royalties payable	0	0
Derivative instruments	0
Total current liabilities	3	6
Long-term debt	157	411
Derivative instruments	0	0
Asset retirement obligations	0	0
Deferred income taxes	0	0
Other long-term liabilities	0	0
Total liabilities	160	417
Commitments and contingencies
Stockholders’ equity	819	542
Non-controlling interest	788	695
Total equity	1,607	1,237
Total liabilities and equity	$ 1,767	$ 1,654

Guarantor Financial Statement_3

Guarantor Financial Statements - Income Statement (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenues:
Lease bonus	$ 1	$ 0
Other operating income	2	2
Revenue	864	479
Costs and expenses:
Lease operating expenses	109	37
Production and ad valorem taxes	55	27
Depreciation, depletion and amortization	322	115
General and administrative expenses	27	16
Asset retirement obligation accretion	2	1
Other operating expense	1	1
Total costs and expenses	545	212
Income (loss) from operations	319	267
Other income (expense):
Interest expense, net	(46)	(14)
Other income (expense), net	1	3
Loss on derivative instruments, net	(268)	(32)
Gain on revaluation of investment	4	1
Total other income (expense), net	(309)	(42)
Income (loss) before income taxes	10	225
Provision for (benefit from) income taxes	(33)	47
Net income	43	178
Net income attributable to non-controlling interest	33	15
Net income (loss) attributable to Diamondback Energy, Inc.	10	163
Eliminations [Member]
Revenues:
Lease bonus	0
Other operating income	0	0
Revenue	0	(1)
Costs and expenses:
Lease operating expenses	0	0
Production and ad valorem taxes	0	0
Depreciation, depletion and amortization	6	3
General and administrative expenses	0	0
Asset retirement obligation accretion	0	0
Other operating expense	0	0
Total costs and expenses	6	3
Income (loss) from operations	(6)	(4)
Other income (expense):
Interest expense, net	0	0
Other income (expense), net	0	0
Loss on derivative instruments, net	0	0
Gain on revaluation of investment	0	0
Total other income (expense), net	0	0
Income (loss) before income taxes	(6)	(4)
Provision for (benefit from) income taxes	0	0
Net income	(6)	(4)
Net income attributable to non-controlling interest	(7)	15
Net income (loss) attributable to Diamondback Energy, Inc.	1	(19)
Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Lease bonus	0
Other operating income	0	0
Revenue	0	0
Costs and expenses:
Lease operating expenses	0	0
Production and ad valorem taxes	0	0
Depreciation, depletion and amortization	0	0
General and administrative expenses	15	7
Asset retirement obligation accretion	0	0
Other operating expense	0	0
Total costs and expenses	15	7
Income (loss) from operations	(15)	(7)
Other income (expense):
Interest expense, net	(10)	(9)
Other income (expense), net	0	0
Loss on derivative instruments, net	0	0
Gain on revaluation of investment	0	0
Total other income (expense), net	(10)	(9)
Income (loss) before income taxes	(25)	(16)
Provision for (benefit from) income taxes	2	47
Net income	(27)	(63)
Net income attributable to non-controlling interest	0	0
Net income (loss) attributable to Diamondback Energy, Inc.	(27)	(63)
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Lease bonus	0
Other operating income	2	2
Revenue	803	418
Costs and expenses:
Lease operating expenses	109	37
Production and ad valorem taxes	51	23
Depreciation, depletion and amortization	300	100
General and administrative expenses	11	7
Asset retirement obligation accretion	2	1
Other operating expense	1	1
Total costs and expenses	503	184
Income (loss) from operations	300	234
Other income (expense):
Interest expense, net	(30)	(3)
Other income (expense), net	1	3
Loss on derivative instruments, net	(268)	(32)
Gain on revaluation of investment	0	0
Total other income (expense), net	(297)	(32)
Income (loss) before income taxes	3	202
Provision for (benefit from) income taxes	0	0
Net income	3	202
Net income attributable to non-controlling interest	0	0
Net income (loss) attributable to Diamondback Energy, Inc.	3	202
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Lease bonus	1
Other operating income	0	0
Revenue	61	62
Costs and expenses:
Lease operating expenses	0	0
Production and ad valorem taxes	4	4
Depreciation, depletion and amortization	16	12
General and administrative expenses	1	2
Asset retirement obligation accretion	0	0
Other operating expense	0	0
Total costs and expenses	21	18
Income (loss) from operations	40	44
Other income (expense):
Interest expense, net	(6)	(2)
Other income (expense), net	0	0
Loss on derivative instruments, net	0	0
Gain on revaluation of investment	4	1
Total other income (expense), net	(2)	(1)
Income (loss) before income taxes	38	43
Provision for (benefit from) income taxes	(35)	0
Net income	73	43
Net income attributable to non-controlling interest	40	0
Net income (loss) attributable to Diamondback Energy, Inc.	33	43
Oil sales
Revenues:
Revenue	743	419
Oil sales | Eliminations [Member]
Revenues:
Revenue	52	55
Oil sales | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Oil sales | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	691	364
Oil sales | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Natural gas sales
Revenues:
Revenue	29	14
Natural gas sales | Eliminations [Member]
Revenues:
Revenue	4	2
Natural gas sales | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Natural gas sales | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	25	12
Natural gas sales | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Natural gas liquid sales
Revenues:
Revenue	70	33
Natural gas liquid sales | Eliminations [Member]
Revenues:
Revenue	4	4
Natural gas liquid sales | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Natural gas liquid sales | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	66	29
Natural gas liquid sales | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Royalty [Member]
Revenues:
Revenue	0	0
Royalty [Member] | Eliminations [Member]
Revenues:
Revenue	(60)	(62)
Royalty [Member] | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Royalty [Member] | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Royalty [Member] | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	60	62
Midstream services
Revenues:
Revenue	19	11
Costs and expenses:
Cost of Goods and Services Sold	17	11
Midstream services | Eliminations [Member]
Revenues:
Revenue	0	0
Costs and expenses:
Cost of Goods and Services Sold	0	0
Midstream services | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Costs and expenses:
Cost of Goods and Services Sold	0	0
Midstream services | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	19	11
Costs and expenses:
Cost of Goods and Services Sold	17	11
Midstream services | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0
Costs and expenses:
Cost of Goods and Services Sold	0	0
Gathering and Transportation [Member]
Costs and expenses:
Cost of Goods and Services Sold	12	4
Gathering and Transportation [Member] | Eliminations [Member]
Costs and expenses:
Cost of Goods and Services Sold	0	0
Gathering and Transportation [Member] | Parent Company [Member] | Reportable Legal Entities [Member]
Costs and expenses:
Cost of Goods and Services Sold	0	0
Gathering and Transportation [Member] | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Costs and expenses:
Cost of Goods and Services Sold	12	4
Gathering and Transportation [Member] | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Costs and expenses:
Cost of Goods and Services Sold	$ 0	$ 0

Guarantor Financial Statement_4

Guarantor Financial Statements - Cash Flow Statement (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 377	$ 339
Cash flows from investing activities:
Additions to oil and natural gas properties	(569)	(280)
Additions to midstream assets	(58)	(38)
Purchase of other property, equipment and land	(4)	(2)
Acquisition of leasehold interests	(75)	(16)
Acquisition of mineral interests	(82)	(150)
Funds held in escrow	0	11
Equity investments	(149)	0
Intercompany transfers		0
Investment in real estate	0	(110)
Net cash used in investing activities	(937)	(585)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	484	224
Repayment under credit facility	(314)	(308)
Proceeds from senior notes	0	312
Proceeds from joint venture	23	0
Debt issuance costs	(3)	(3)
Proceeds from public offerings	341	0
Distributions from subsidiary	0	0
Dividends to stockholders	(21)	0
Repurchased shares for tax withholding	(13)	0
Distributions to non-controlling interest	(26)	(19)
Intercompany transfers	0	0
Net cash provided by financing activities	471	206
Net increase (decrease) in cash and cash equivalents	(89)	(40)
Cash and cash equivalents at beginning of period	215	112
Cash and cash equivalents at end of period	126	72
Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0	0
Cash flows from investing activities:
Additions to oil and natural gas properties	0	0
Additions to midstream assets	0	0
Purchase of other property, equipment and land	0	0
Acquisition of leasehold interests	0	0
Acquisition of mineral interests	0	0
Funds held in escrow		0
Equity investments	0
Intercompany transfers		0
Investment in real estate		0
Net cash used in investing activities	0	0
Cash flows from financing activities:
Proceeds from borrowing under credit facility	0	0
Repayment under credit facility	0	0
Proceeds from senior notes		0
Proceeds from joint venture	0
Debt issuance costs	0	0
Proceeds from public offerings	0
Distributions from subsidiary	(37)	(33)
Dividends to stockholders	0
Repurchased shares for tax withholding	0
Distributions to non-controlling interest	37	33
Intercompany transfers	0	0
Net cash provided by financing activities	0	0
Net increase (decrease) in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Parent Company [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	16	27
Cash flows from investing activities:
Additions to oil and natural gas properties	0	0
Additions to midstream assets	0	0
Purchase of other property, equipment and land	0	0
Acquisition of leasehold interests	0	0
Acquisition of mineral interests	0	0
Funds held in escrow		0
Equity investments	0
Intercompany transfers		(87)
Investment in real estate		0
Net cash used in investing activities	0	(87)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	0	0
Repayment under credit facility	0	0
Proceeds from senior notes		312
Proceeds from joint venture	0
Debt issuance costs	0	(3)
Proceeds from public offerings	0
Distributions from subsidiary	37	33
Dividends to stockholders	(21)
Repurchased shares for tax withholding	(13)
Distributions to non-controlling interest	0	0
Intercompany transfers	18	(308)
Net cash provided by financing activities	21	34
Net increase (decrease) in cash and cash equivalents	37	(26)
Cash and cash equivalents at beginning of period	84	54
Cash and cash equivalents at end of period	121	28
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	316	263
Cash flows from investing activities:
Additions to oil and natural gas properties	(569)	(280)
Additions to midstream assets	(58)	(38)
Purchase of other property, equipment and land	(4)	(2)
Acquisition of leasehold interests	(75)	(16)
Acquisition of mineral interests	0	0
Funds held in escrow		11
Equity investments	(149)
Intercompany transfers		87
Investment in real estate		(110)
Net cash used in investing activities	(855)	(348)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	424	77
Repayment under credit facility	0	(308)
Proceeds from senior notes		0
Proceeds from joint venture	23
Debt issuance costs	(3)	0
Proceeds from public offerings	0
Distributions from subsidiary	0	0
Dividends to stockholders	0
Repurchased shares for tax withholding	0
Distributions to non-controlling interest	0	0
Intercompany transfers	(18)	308
Net cash provided by financing activities	426	77
Net increase (decrease) in cash and cash equivalents	(113)	(8)
Cash and cash equivalents at beginning of period	108	34
Cash and cash equivalents at end of period	(5)	26
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	45	49
Cash flows from investing activities:
Additions to oil and natural gas properties	0	0
Additions to midstream assets	0	0
Purchase of other property, equipment and land	0	0
Acquisition of leasehold interests	0	0
Acquisition of mineral interests	(82)	(150)
Funds held in escrow		0
Equity investments	0
Intercompany transfers		0
Investment in real estate		0
Net cash used in investing activities	(82)	(150)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	60	147
Repayment under credit facility	(314)	0
Proceeds from senior notes		0
Proceeds from joint venture	0
Debt issuance costs	0	0
Proceeds from public offerings	341
Distributions from subsidiary	0	0
Dividends to stockholders	0
Repurchased shares for tax withholding	0
Distributions to non-controlling interest	(63)	(52)
Intercompany transfers	0	0
Net cash provided by financing activities	24	95
Net increase (decrease) in cash and cash equivalents	(13)	(6)
Cash and cash equivalents at beginning of period	23	24
Cash and cash equivalents at end of period	$ 10	$ 18