Cover
Cover - shares | 3 Months Ended | |
Mar. 31, 2020 | May 01, 2020 | |
Cover [Abstract] | ||
Document type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Mar. 31, 2020 | |
Document Transition Report | false | |
Entity File Number | 001-35700 | |
Entity Registrant Name | Diamondback Energy, Inc. | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 45-4502447 | |
Entity Address, Address Line One | 500 West Texas | |
Entity Address, Address Line Two | Suite 1200 | |
Entity Address, City or Town | Midland, | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 79701 | |
City Area Code | 432 | |
Local Phone Number | 221-7400 | |
Title of 12(b) Security | Common Stock | |
Trading Symbol | FANG | |
Security Exchange Name | NASDAQ | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 157,815,843 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2020 | |
Document Fiscal Period Focus | Q1 | |
Entity Central Index Key | 0001539838 | |
Current Fiscal Year End Date | --12-31 |
Consolidated Balance Sheets (Un
Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 |
Current assets: | ||
Cash and cash equivalents | $ 149 | $ 123 |
Restricted cash | 6 | 5 |
Accounts receivable: | ||
Joint interest and other, net | 178 | 186 |
Oil and natural gas sales, net | 225 | 429 |
Inventories | 36 | 37 |
Derivative instruments | 534 | 46 |
Prepaid expenses and other current assets | 140 | 43 |
Total current assets | 1,268 | 869 |
Property and equipment: | ||
Oil and natural gas properties, full cost method of accounting ($8,488 million and $9,207 million excluded from amortization at March 31, 2020 and December 31, 2019, respectively) | 26,719 | 25,782 |
Midstream assets | 987 | 931 |
Other property, equipment and land | 130 | 125 |
Accumulated depletion, depreciation, amortization and impairment | (6,416) | (5,003) |
Net property and equipment | 21,420 | 21,835 |
Equity method investments | 502 | 479 |
Derivative instruments | 30 | 7 |
Deferred tax asset, net | 0 | 142 |
Investment in real estate, net | 107 | 109 |
Other assets | 59 | 90 |
Total assets | 23,386 | 23,531 |
Current liabilities: | ||
Accounts payable-trade | 245 | 179 |
Accrued capital expenditures | 490 | 475 |
Other accrued liabilities | 287 | 304 |
Revenues and royalties payable | 292 | 278 |
Derivative instruments | 16 | 27 |
Total current liabilities | 1,330 | 1,263 |
Long-term debt | 5,677 | 5,371 |
Derivative instruments | 66 | 0 |
Asset retirement obligations | 99 | 94 |
Deferred income taxes | 1,888 | 1,886 |
Other long-term liabilities | 10 | 11 |
Total liabilities | 9,070 | 8,625 |
Commitments and contingencies (Note 18) | ||
Stockholders’ equity: | ||
Common stock, $0.01 par value, 200,000,000 shares authorized, 157,815,843 issued and outstanding at March 31, 2020; 200,000,000 shares authorized, 159,002,338 issued and outstanding at December 31, 2019 | 2 | 2 |
Additional paid-in capital | 12,265 | 12,357 |
Retained earnings | 559 | 890 |
Total Diamondback Energy, Inc. stockholders’ equity | 12,826 | 13,249 |
Non-controlling interest | 1,490 | 1,657 |
Total equity | 14,316 | 14,906 |
Total liabilities and equity | $ 23,386 | $ 23,531 |
Consolidated Balance Sheets (_2
Consolidated Balance Sheets (Unaudited) Consolidated Balance Sheets (Unaudited) (Parentheticals) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 |
Statement of Financial Position [Abstract] | ||
Oil and natural gas properties, amortization excluded | $ 8,488 | $ 9,207 |
Common Stock, Par Value (in dollars per share) | $ 0.01 | $ 0.01 |
Shares authorized (in Shares) | 200,000,000 | 200,000,000 |
Shares Issued (in Shares) | 157,815,843 | 159,002,338 |
Shares Outstanding (in Shares) | 157,815,843 | 159,002,338 |
Consolidated Statements of Oper
Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Millions | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Revenues: | ||
Lease bonus | $ 0 | $ 1 |
Other operating income | 2 | 2 |
Total revenues | 899 | 864 |
Costs and expenses: | ||
Lease operating expenses | 127 | 109 |
Production and ad valorem taxes | 71 | 55 |
Depreciation, depletion and amortization | 407 | 322 |
Impairment of oil and natural gas properties | 1,009 | 0 |
General and administrative expenses | 24 | 27 |
Asset retirement obligation accretion | 2 | 2 |
Other operating expense | 2 | 1 |
Total costs and expenses | 1,701 | 545 |
Income (loss) from operations | (802) | 319 |
Other income (expense): | ||
Interest expense, net | (48) | (46) |
Other income, net | 1 | 1 |
Gain (loss) on derivative instruments, net | 542 | (268) |
(Loss) gain on revaluation of investment | (10) | 4 |
Total other income (expense), net | 485 | (309) |
Income (loss) before income taxes | (317) | 10 |
Provision for (benefit from) income taxes | 83 | (33) |
Net (loss) income | (400) | 43 |
Net (loss) income attributable to non-controlling interest | (128) | 33 |
Net (loss) income attributable to Diamondback Energy, Inc. | $ (272) | $ 10 |
Earnings per common share: | ||
Basic (in USD per share) | $ (1.72) | $ 0.06 |
Diluted (in USD per share) | $ (1.72) | $ 0.06 |
Weighted average common shares outstanding: | ||
Basic (in shares) | 158,291 | 164,852 |
Diluted (in shares) | 158,494 | 165,061 |
Dividends declared per share (in USD per share) | $ 0.3750 | $ 0.1875 |
Oil sales | ||
Revenues: | ||
Revenue | $ 827 | $ 743 |
Natural gas sales | ||
Revenues: | ||
Revenue | 4 | 29 |
Natural gas liquid sales | ||
Revenues: | ||
Revenue | 52 | 70 |
Midstream services | ||
Revenues: | ||
Revenue | 14 | 19 |
Costs and expenses: | ||
Cost of goods and services sold | 23 | 17 |
Gathering and transportation | ||
Costs and expenses: | ||
Cost of goods and services sold | $ 36 | $ 12 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Millions | Total | Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Non-Controlling Interest |
Balance at beginning of period at Dec. 31, 2018 | $ 14,167 | $ 2 | $ 12,936 | $ 762 | $ 467 |
Balance at beginning of period (in Shares) at Dec. 31, 2018 | 164,273,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net proceeds from issuance of common units - Viper Energy Partners LP | 341 | 341 | |||
Stock-based compensation | 19 | 19 | |||
Repurchased shares for tax withholding | (13) | (13) | |||
Repurchased shares for tax withholding (in Shares) | (125,000) | ||||
Distribution to non-controlling interest | (26) | (26) | |||
Dividend paid | (20) | (20) | |||
Exercise of stock options and vesting of restricted stock units | 0 | ||||
Exercise of stock and unit options and awards of restricted stock (in Shares) | 468,000 | ||||
Change in ownership of consolidated subsidiaries, net | 3 | 77 | (74) | ||
Net (loss) income | 43 | 10 | 33 | ||
Balance at end of period at Mar. 31, 2019 | 14,514 | $ 2 | 13,019 | 752 | 741 |
Balance at end of period (in Shares) at Mar. 31, 2019 | 164,616,000 | ||||
Balance at beginning of period at Dec. 31, 2019 | $ 14,906 | $ 2 | 12,357 | 890 | 1,657 |
Balance at beginning of period (in Shares) at Dec. 31, 2019 | 159,002,338 | 159,002,000 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Unit-based compensation | $ 5 | 5 | |||
Distribution equivalent rights payments | (1) | (1) | |||
Stock-based compensation | 10 | 10 | |||
Repurchased shares for tax withholding | (5) | (5) | |||
Repurchased shares for share buyback program | (98) | (98) | |||
Repurchased shares for share buyback program (in Shares) | (1,280,000) | ||||
Distribution to non-controlling interest | (43) | (43) | |||
Dividend paid | (59) | (59) | |||
Exercise of stock options and vesting of restricted stock units | 1 | 1 | |||
Exercise of stock and unit options and awards of restricted stock (in Shares) | 93,000 | ||||
Change in ownership of consolidated subsidiaries, net | 0 | 0 | 0 | ||
Net (loss) income | (400) | (272) | (128) | ||
Balance at end of period at Mar. 31, 2020 | $ 14,316 | $ 2 | $ 12,265 | $ 559 | $ 1,490 |
Balance at end of period (in Shares) at Mar. 31, 2020 | 157,815,843 | 157,815,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Cash flows from operating activities: | ||
Net (loss) income | $ (400) | $ 43 |
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||
Provision for (benefit from) deferred income taxes | 83 | (33) |
Impairment of oil and natural gas properties | 1,009 | 0 |
Asset retirement obligation accretion | 2 | 2 |
Depreciation, depletion and amortization | 407 | 322 |
Amortization of debt issuance costs | 2 | 1 |
Change in fair value of derivative instruments | (455) | 285 |
Loss (gain) on revaluation of investment | 10 | (4) |
Equity-based compensation expense | 9 | 14 |
Changes in operating assets and liabilities: | ||
Accounts receivable | 175 | (63) |
Inventories | 1 | (4) |
Prepaid expenses and other | (4) | (9) |
Accounts payable and accrued liabilities | (35) | (190) |
Accrued interest | 31 | 5 |
Revenues and royalties payable | 14 | 8 |
Net cash provided by operating activities | 849 | 377 |
Cash flows from investing activities: | ||
Drilling, completions and non-operated additions to oil and natural gas properties | (690) | (533) |
Infrastructure additions to oil and natural gas properties | (56) | (36) |
Additions to midstream assets | (44) | (58) |
Purchase of other property, equipment and land | (5) | (4) |
Acquisition of leasehold interests | (40) | (75) |
Acquisitions of mineral interests | (65) | (82) |
Contributions to equity method investments | (33) | (149) |
Distributions from equity method investments | 10 | 0 |
Net cash used in investing activities | (923) | (937) |
Cash flows from financing activities: | ||
Proceeds from borrowings under credit facility | 430 | 484 |
Repayments under credit facility | (140) | (314) |
Proceeds from joint venture | 16 | 23 |
Debt issuance costs | 0 | (3) |
Proceeds from public offerings | 0 | 341 |
Proceeds from exercise of stock options | 1 | 0 |
Repurchased shares for tax withholdings | (5) | (13) |
Repurchased shares as part of share buyback | (98) | 0 |
Distribution equivalent rights | (1) | 0 |
Dividends to stockholders | (59) | (21) |
Distributions to non-controlling interest | (43) | (26) |
Net cash (used in) provided by financing activities | 101 | 471 |
Net increase (decrease) in cash and cash equivalents | 27 | (89) |
Cash and cash equivalents at beginning of period | 128 | 215 |
Cash and cash equivalents at end of period | 155 | 126 |
Supplemental disclosure of cash flow information: | ||
Interest paid, net of capitalized interest | 16 | 17 |
Supplemental disclosure of non-cash transactions: | ||
Change in accrued capital expenditures | 15 | (10) |
Capitalized stock-based compensation | 6 | 6 |
Asset retirement obligations acquired | $ 0 | $ 3 |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) $ in Millions | Mar. 31, 2019USD ($) |
Total cash, cash equivalents and restricted cash shown in statement of cash flows | |
Cash and cash equivalents | $ 149 |
Restricted cash | 6 |
Total cash, cash equivalents and restricted cash shown in statement of cash flows | $ 126 |
DESCRIPTION OF THE BUSINESS AND
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION | 3 Months Ended |
Mar. 31, 2020 | |
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., together with its subsidiaries (collectively referred to as “Diamondback” or the “Company” unless the context otherwise requires), 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, 2020 , 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 (“Energen”). The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (“Viper”), Viper’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company (“Viper LLC”), Rattler Midstream LP, a Delaware limited partnership (“Rattler”), Rattler Midstream Operating LLC, a Delaware limited liability company (“Rattler LLC”), Rattler LLC’s wholly-owned subsidiary Tall City Towers LLC, a Delaware limited liability company (“Tall City”), and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation, and EGN Services, Inc., an Alabama corporation. 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. Viper is consolidated in the financial statements of the Company. As of March 31, 2020 , the Company owned approximately 58% of Viper’s total units outstanding. The Company’s wholly-owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. Rattler is consolidated in the financial statements of the Company. As of March 31, 2020 , the Company owned approximately 71% of Rattler’s total units outstanding. The Company’s wholly-owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. 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, 2019 , which contains a summary of the Company’s significant accounting policies and other disclosures. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 3 Months Ended |
Mar. 31, 2020 | |
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. Making accurate estimates and assumptions are particularly difficult as the oil and gas industry experiences challenges resulting from negative pricing pressure from the effects of a decline in worldwide economic conditions. The decline in worldwide economic conditions is the result of a global COVID-19 pandemic announced in March 2020, which has reduced economic activity and resulted in a significant decline in the short term demand for oil and gas production. Companies in the oil and gas industry are beginning to change near term business plans in response to changing market conditions. The aforementioned circumstances generally increases the estimation uncertainty in our accounting estimates, particularly the accounting estimates involving financial forecasts. 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 derivative instruments and estimates of income taxes. Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date. The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. The adoption of ASU 2016-13 did not result in a material change to the Company’s allowance. At March 31, 2020 , the Company recorded an allowance for doubtful accounts of $1 million related to joint interest and other receivables and $1 million related to oil and natural gas sales receivables. Recent Accounting Pronouncements The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements: Standard Description Date of Adoption Effect on Financial Statements or Other Significant Matters Recently Adopted Pronouncements ASU 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. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses. ASU 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. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels. ASU 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. Q1 2020 The Company adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)” This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any cost method investments. ASU 2020-04, “Rate Reform (Topic 848)” This update provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference LIBOR. Q1 2020 The Company adopted this update upon issuance and elected to use the optional expedient for contracts and hedging that reference LIBOR. The amendments in this update expire on December 31, 2022. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. Pronouncements Not Yet Adopted ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes” This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance. Q1 2021 This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will 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, 2020 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE FROM CONTRACTS WITH CUSTOMERS | 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 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 ASC 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, 2020 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded. |
VIPER ENERGY PARTNERS LP
VIPER ENERGY PARTNERS LP | 3 Months Ended |
Mar. 31, 2020 | |
Noncontrolling Interest [Abstract] | |
VIPER ENERGY PARTNERS LP | VIPER ENERGY PARTNERS LP Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper is currently focused on owning and acquiring mineral interests and royalty interests in 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 Viper. As of March 31, 2020 , the Company owned approximately 58% of Viper’s total units outstanding. 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 “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s 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 Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the three months ended March 31, 2020 and 2019 , Viper’s General Partner allocated $1 million to Viper. Tax Sharing In connection with the closing of the Viper Offering, Viper entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which Viper agreed to reimburse Diamondback for its share of state and local income and other taxes for which Viper’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 Viper 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 Viper may be a member for this purpose, to owe less or no tax. In such a situation, Viper agreed to reimburse Diamondback for the tax Viper would have owed had the tax attributes not been available or used for Viper’s benefit, even though Diamondback had no cash tax expense for that period. For the three months ended March 31, 2020 and 2019 , Viper accrued a minimal amount of state income tax expense for its share of Texas margin tax for which Viper’s results are included in a combined tax return filed by Diamondback. Viper LLC’s Revolving Credit Facility Viper LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent sole book runner and lead arranger. See Note 10 — Debt for a description of this credit facility. Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR.” Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler Midstream GP LLC (“Rattler’s General Partner”), a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of March 31, 2020 , Diamondback owned approximately 71% of Rattler’s total units outstanding. Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed on May 30, 2019. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions. In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution from Rattler’s General Partner, and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly. Diamondback has also entered into the following agreements with Rattler: Rattler’s Partnership Agreement In connection with the closing of the Rattler Offering, Rattler’s General Partner and Energen Resources Corporation entered into the first amended and restated agreement of limited partnership of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner for all direct and indirect expenses incurred or paid on Rattler’s behalf and all other expenses allocable to Rattler or otherwise incurred by Rattler’s General Partner in connection with operating Rattler’s business. The Rattler Partnership Agreement does not set a limit on the amount of expenses for which its 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 Rattler or on its behalf and expenses allocated to Rattler’s General Partner by its affiliates. Rattler’s General Partner is entitled to determine the expenses that are allocable to Rattler. For the three months ended March 31, 2020 , the General Partner allocated $0.1 million of such expenses to Rattler. Rattler’s Services and Secondment Agreement In connection with the closing of the Rattler Offering, Rattler entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, Rattler’s General Partner and Rattler LLC, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to Rattler’s General Partner, Rattler and its subsidiaries, providing management, maintenance and operational functions with respect to Rattler’s assets. The Services and Secondment Agreement requires Rattler’s General Partner and Rattler to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the three months ended March 31, 2020 , Rattler’s General Partner and Rattler paid Diamondback $2 million under the Services and Secondment Agreement. Rattler’s Tax Sharing Agreement In connection with the closing of the Rattler Offering, Rattler LLC entered into a tax sharing agreement with Diamondback pursuant to which Rattler LLC will reimburse Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of Rattler LLC’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax that Rattler LLC 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 Rattler LLC may be a member for this purpose, to owe less or no tax. In such a situation, Rattler LLC agreed to reimburse Diamondback for the tax Rattler LLC would have owed had the attributes not been available or used for Rattler LLC’s benefit, even though Diamondback had no cash expense for that period. For the three months ended March 31, 2020 , Rattler accrued state income tax expense of $0.1 million of Texas margin tax and the portion attributable to Rattler is included in a combined tax return filed by Diamondback. Other Agreements Rattler has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 10 — Debt for a description of this credit facility. |
RATTLER MIDSTREAM LP
RATTLER MIDSTREAM LP | 3 Months Ended |
Mar. 31, 2020 | |
Noncontrolling Interest [Abstract] | |
RATTLER MIDSTREAM LP | VIPER ENERGY PARTNERS LP Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper is currently focused on owning and acquiring mineral interests and royalty interests in 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 Viper. As of March 31, 2020 , the Company owned approximately 58% of Viper’s total units outstanding. 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 “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s 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 Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the three months ended March 31, 2020 and 2019 , Viper’s General Partner allocated $1 million to Viper. Tax Sharing In connection with the closing of the Viper Offering, Viper entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which Viper agreed to reimburse Diamondback for its share of state and local income and other taxes for which Viper’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 Viper 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 Viper may be a member for this purpose, to owe less or no tax. In such a situation, Viper agreed to reimburse Diamondback for the tax Viper would have owed had the tax attributes not been available or used for Viper’s benefit, even though Diamondback had no cash tax expense for that period. For the three months ended March 31, 2020 and 2019 , Viper accrued a minimal amount of state income tax expense for its share of Texas margin tax for which Viper’s results are included in a combined tax return filed by Diamondback. Viper LLC’s Revolving Credit Facility Viper LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent sole book runner and lead arranger. See Note 10 — Debt for a description of this credit facility. Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR.” Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler Midstream GP LLC (“Rattler’s General Partner”), a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of March 31, 2020 , Diamondback owned approximately 71% of Rattler’s total units outstanding. Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed on May 30, 2019. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions. In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution from Rattler’s General Partner, and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly. Diamondback has also entered into the following agreements with Rattler: Rattler’s Partnership Agreement In connection with the closing of the Rattler Offering, Rattler’s General Partner and Energen Resources Corporation entered into the first amended and restated agreement of limited partnership of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner for all direct and indirect expenses incurred or paid on Rattler’s behalf and all other expenses allocable to Rattler or otherwise incurred by Rattler’s General Partner in connection with operating Rattler’s business. The Rattler Partnership Agreement does not set a limit on the amount of expenses for which its 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 Rattler or on its behalf and expenses allocated to Rattler’s General Partner by its affiliates. Rattler’s General Partner is entitled to determine the expenses that are allocable to Rattler. For the three months ended March 31, 2020 , the General Partner allocated $0.1 million of such expenses to Rattler. Rattler’s Services and Secondment Agreement In connection with the closing of the Rattler Offering, Rattler entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, Rattler’s General Partner and Rattler LLC, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to Rattler’s General Partner, Rattler and its subsidiaries, providing management, maintenance and operational functions with respect to Rattler’s assets. The Services and Secondment Agreement requires Rattler’s General Partner and Rattler to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the three months ended March 31, 2020 , Rattler’s General Partner and Rattler paid Diamondback $2 million under the Services and Secondment Agreement. Rattler’s Tax Sharing Agreement In connection with the closing of the Rattler Offering, Rattler LLC entered into a tax sharing agreement with Diamondback pursuant to which Rattler LLC will reimburse Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of Rattler LLC’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax that Rattler LLC 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 Rattler LLC may be a member for this purpose, to owe less or no tax. In such a situation, Rattler LLC agreed to reimburse Diamondback for the tax Rattler LLC would have owed had the attributes not been available or used for Rattler LLC’s benefit, even though Diamondback had no cash expense for that period. For the three months ended March 31, 2020 , Rattler accrued state income tax expense of $0.1 million of Texas margin tax and the portion attributable to Rattler is included in a combined tax return filed by Diamondback. Other Agreements Rattler has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 10 — Debt for a description of this credit facility. |
REAL ESTATE ASSETS
REAL ESTATE ASSETS | 3 Months Ended |
Mar. 31, 2020 | |
Real Estate [Abstract] | |
REAL ESTATE ASSETS | 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, 2020 December 31, 2019 (Years) (in millions) Buildings 20-30 $ 102 $ 102 Tenant improvements 15 5 5 Land N/A 2 2 Land improvements 15 1 1 Total real estate assets 110 110 Less: accumulated depreciation (10 ) (9 ) Total investment in land and buildings, net $ 100 $ 101 Weighted Average Useful Lives March 31, 2020 December 31, 2019 (Months) (in millions) In-place lease intangibles 45 $ 11 $ 11 Less: accumulated amortization (6 ) (6 ) In-place lease intangibles, net 5 5 Above-market lease intangibles 45 3 4 Less: accumulated amortization (1 ) (1 ) Above-market lease intangibles, net 2 3 Total intangible lease assets, net $ 7 $ 8 |
PROPERTY AND EQUIPMENT
PROPERTY AND EQUIPMENT | 3 Months Ended |
Mar. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY AND EQUIPMENT | PROPERTY AND EQUIPMENT Property and equipment includes the following as of the dates indicated: March 31, December 31, 2020 2019 (in millions) Oil and natural gas properties: Subject to depletion $ 18,231 $ 16,575 Not subject to depletion 8,488 9,207 Gross oil and natural gas properties 26,719 25,782 Accumulated depletion (3,387 ) (2,995 ) Accumulated impairment (2,943 ) (1,934 ) Oil and natural gas properties, net 20,389 20,853 Midstream assets 987 931 Other property, equipment and land 130 125 Accumulated depreciation (86 ) (74 ) Total property and equipment, net $ 21,420 $ 21,835 Balance of costs not subject to depletion: Incurred in 2020 $ 59 Incurred in 2019 604 Incurred in 2018 5,398 Incurred in 2017 2,124 Incurred in 2016 303 Total not subject to depletion $ 8,488 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 $14 million and $13 million for the three months ended March 31, 2020 and 2019 , 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 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 of the acreage, associated with acquisition costs not currently being amortized, expire based on current drilling plans. 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. As a result of the sharp decline in commodity prices during the first quarter of 2020, the Company recorded a non-cash ceiling test impairment for the three months ended March 31, 2020 of $1.0 billion which was included in accumulated depletion. The impairment charge affected the Company’s results of operations but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, the Company will have material write downs in subsequent quarters. No impairment on proved oil and natural gas properties was recorded for the three months ended March 31, 2019 . The Company evaluates its long-lived assets (primarily comprised of midstream assets) for potential impairment whenever events or circumstances indicate it is more likely than not that the carrying amount of the asset, or set of assets, is greater than the fair value. An impairment involves comparing the estimated future undiscounted cash flows of an asset or set of assets with the carrying amount. If the carrying amount of the asset or set of assets exceeds the estimated undiscounted cash flows, then an impairment charge is recorded for the difference between the estimated fair value of the asset or set of assets and its carrying value. Given the rate of change impacting the oil and gas industry described above, it is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded. At March 31, 2020 , $228 million in exploration costs and development costs and $111 million in capitalized interest was not subject to depletion. At December 31, 2019 , $228 million in exploration costs and development costs and $118 million in capitalized interest was not subject to depletion. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 3 Months Ended |
Mar. 31, 2020 | |
Asset Retirement Obligation [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS The following table describes the changes to the Company’s asset retirement obligations liability for the following periods: Three Months Ended March 31, 2020 2019 (in millions) Asset retirement obligations, beginning of period $ 94 $ 136 Additional liabilities incurred 4 1 Liabilities acquired — 3 Liabilities settled — (2 ) Accretion expense 2 2 Revisions in estimated liabilities — — Asset retirement obligations, end of period 100 140 Less current portion 1 — Asset retirement obligations - long-term $ 99 $ 140 The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance. The current portion of the asset retirement obligation liability is included in other accrued liabilities in the Company’s consolidated balance sheets. |
EQUITY METHOD INVESTMENTS
EQUITY METHOD INVESTMENTS | 3 Months Ended |
Mar. 31, 2020 | |
Equity Method Investments and Joint Ventures [Abstract] | |
EQUITY METHOD INVESTMENTS | EQUITY METHOD INVESTMENTS The following table presents the carrying values of Rattler’s equity method investments as of the dates indicated: Ownership Interest March 31, 2020 December 31, 2019 (in millions) EPIC Crude Holdings, LP 10 % $ 117 $ 109 Gray Oak Pipeline, LLC 10 % 122 116 Wink to Webster Pipeline LLC 4 % 45 34 OMOG JV LLC 60 % 216 219 Amarillo Rattler, LLC 50 % 2 1 $ 502 $ 479 Income (loss) from equity method investees was not material for the three months ended March 31, 2020 or 2019 . On February 1, 2019, Rattler LLC acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which owns and operates a pipeline (the “EPIC pipeline”) that transports crude and NGL across Texas for delivery into the Corpus Christi market. The EPIC pipeline became fully operational in April 2020. On February 15, 2019, Rattler LLC acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which owns and operates a pipeline (the “Gray Oak pipeline”) that transports crude from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak pipeline became fully operational in April 2020. On March 29, 2019, Rattler LLC 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. The short-term promissory note was repaid on May 31, 2019. During the three months ended March 31, 2020 , there were no borrowings or repayments under this note. There were no outstanding loans at March 31, 2020 . On June 4, 2019, Rattler entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement requires Rattler to contribute equity or make loans to Gray Oak so that Gray Oak can, to the extent necessary, cure payment defaults under Gray Oak’s credit agreement and, in certain instances, repay Gray Oak’s credit agreement in full. Rattler’s obligations under the equity contribution agreement are limited to its proportionate ownership interest in Gray Oak, and such obligations are guaranteed by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. On July 30, 2019, Rattler LLC joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP and Lotus Midstream. The joint venture is developing a crude oil pipeline with origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations (the “Wink to Webster pipeline”). The Wink to Webster pipeline is expected to begin service in the first half of 2021. On October 1, 2019, Rattler LLC acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which owns and operates a crude oil gathering system in the Permian Basin, and was renamed as Oryx Midland Oil Gathering LLC following the acquisition. Although Rattler’s equity interest is 60% , the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling minority investor. On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler, LLC, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas as well as incremental gas gathering and compression and regional transportation pipelines. Although Rattler’s equity interest is 50% , the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling investor. Rattler reviews its investments to determine if a loss in value which is other than temporary has occurred. If such a loss has occurred, Rattler recognizes an impairment provision. No impairments were recorded for Rattler’s equity method investments for the three months ended March 31, 2020 or 2019 . Rattler’s investees all serve customers in the oil and gas industry, which has begun to experience economic challenges as described above. It is possible that prolonged industry challenges could result in circumstances requiring impairment testing, which could result in potentially material impairment charges in future interim periods. During the three months ended March 31, 2020 , $0.3 million of capitalized interest was related to equity method investments that have not yet begun operations. There was no capitalized interest during the three months ended March 31, 2019 . |
DEBT
DEBT | 3 Months Ended |
Mar. 31, 2020 | |
Debt Disclosure [Abstract] | |
DEBT | DEBT Long-term debt consisted of the following as of the dates indicated: March 31, December 31, 2020 2019 (in millions) 4.625% Notes due 2021 $ 400 $ 399 7.320% Medium-term Notes, Series A, due 2022 20 21 2.875% Senior Notes due 2024 1,000 1,000 5.375% Senior Notes due 2025 800 800 3.250% Senior Notes due 2026 800 800 7.350% Medium-term Notes, Series A, due 2027 10 11 7.125% Medium-term Notes, Series B, due 2028 100 108 3.500% Senior Notes due 2029 1,200 1,200 DrillCo Agreement 55 39 Unamortized debt issuance costs (19 ) (19 ) Unamortized discount costs (31 ) (31 ) Unamortized premium costs 18 9 Revolving credit facility 199 13 Viper revolving credit facility 174 97 Viper 5.375% Senior Notes due 2027 500 500 Rattler revolving credit facility 451 424 Total long-term debt $ 5,677 $ 5,371 References in this section to the Company shall mean Diamondback Energy, Inc. and Diamondback O&G LLC, collectively, unless otherwise specified. Diamondback Notes 2025 Senior Notes On December 20, 2016, Diamondback Energy, Inc. issued $500 million in aggregate principal amount of 5.375% senior notes due 2025 (the “existing 2025 notes”), under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (the “2025 indenture”). On January 29, 2018, Diamondback Energy, Inc. issued $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture (the “new 2025 notes” and, together with the existing 2025 notes, the 2025 senior notes). The 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. Diamondback Energy, Inc.’s existing and future restricted subsidiaries that guarantee this revolving credit facility also guarantee the 2025 senior notes. The 2025 senior notes are not and will not be guaranteed by any of Diamondback Energy, Inc.’s unrestricted subsidiaries. Currently, the 2025 senior notes are not guaranteed by any of the Company’s subsidiaries other than Diamondback O&G LLC. 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. The 2025 indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Diamondback Energy, Inc.’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events. December 2019 Notes Offering On December 5, 2019, Diamondback Energy, Inc. issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024 (the “2024 notes”), $800 million in aggregate principal amount of 3.250% senior notes due 2026 (the “2026 notes”), and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, (the “2029 notes” and, together with the 2024 notes and the 2026 notes, the “December 2019 Notes”). The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 Notes are guaranteed by Diamondback O&G LLC and are not guaranteed by any of Diamondback Energy, Inc. other subsidiaries. The December 2019 Notes were issued under an indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019 (collectively, the “December 2019 Notes Indenture”). The C ompany may redeem (i) the 2024 notes in whole or in part at any time prior to November 1, 2024 (one month prior to the maturity date of the 2024 notes), (ii) the 2026 notes in whole or in part at any time prior to October 1, 2026 (two months prior to the maturity date of the 2026 notes) and (iii) the 2029 notes in whole or in part at any time prior to September 1, 2029 (three months prior to the maturity date of the 2029 notes) (each such date, a “par call date”), in each case at a redemption price equal to 100% of the principal amount of such notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. If the December 2019 Notes are redeemed on or after their respective par call dates, in each case, such December 2019 Notes will be redeemed at a redemption price equal to 100% of the principal amount of the December 2019 Notes to be redeemed plus interest accrued thereon to but not including the redemption date. Upon the occurrence of a Change of Control Triggering Event (as defined in the December 2019 Notes Indenture), holders may require the Company to purchase some or all of their December 2019 Notes for cash at a price equal to 101% of the principal amount of the December 2019 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase. The December 2019 Notes Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Diamondback Energy, Inc.’s ability and the ability of certain of its subsidiaries to incur liens securing funded indebtedness and on Diamondback Energy, Inc.’s ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets. Second Amended and Restated Credit Facility Diamondback O&G LLC, as borrower, and Diamondback Energy, Inc., as parent guarantor, 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. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied, which changes became effective on November 20, 2019. As of March 31, 2020 , the maximum credit amount available under the credit agreement is $2.0 billion . As of March 31, 2020 , Diamondback Energy, Inc. had approximately $199 million of outstanding borrowings under its revolving credit facility and $1.8 billion available for future borrowings under the revolving credit facility. The next regularly scheduled annual redetermination of the borrowing base is scheduled for the fall of 2020. Diamondback O&G LLC is the borrower under the credit agreement, and, as of March 31, 2020 , the credit agreement is guaranteed by Diamondback Energy, Inc. None of Diamondback Energy, Inc.’s other subsidiaries are guarantors under the revolving credit facility. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to the 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 0.125% to 1.0% per annum in the case of the alternative base rate and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies’ ratings of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ ratings of our unsecured debt. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022. The credit agreement contains a financial covenant that requires us to maintain a total net debt to capitalization ratio (as defined in the credit agreement) of no more than 65% . Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets. As of March 31, 2020 and December 31, 2019 , the Company was in compliance with all financial covenants under the revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the 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. Energen’s Notes At the effective time of the merger with Energen, Energen became Diamondback Energy, Inc.’s wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”), issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). As of March 31, 2020 , 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, 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 if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes. 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. Viper’s Credit Agreement On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended (the “Viper credit agreement”), provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $775 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, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12 -month period. As of March 31, 2020 , the borrowing base was set at $775 million , and Viper LLC had $174 million of outstanding borrowings and $601 million available for future borrowings under the Viper credit agreement. In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent under the Viper credit agreement has recommended that the borrowing base be decreased under the Viper credit agreement to $580 million effective mid-May 2020. The decrease is subject to approval by the requisite lenders under the Viper credit agreement. Under the new expected borrowing base, Viper LLC would have had $407 million of availability for future borrowings under the Viper credit agreement as of March 31, 2020 . Neither Diamondback Energy, Inc. nor any of its other subsidiaries guarantee the Viper credit agreement. The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected by Viper LLC 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. Viper LLC 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 prepaid 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 Viper and Viper LLC. The Viper 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, purchases of margin stock 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 Viper credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined the Viper 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 $1.0 billion 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. The covenant limiting dividends and distributions includes an exception allowing Viper LLC to make distributions if no default, event of default or borrowing base deficiency exists. As of March 31, 2020 and December 31, 2019 , Viper and Viper LLC were in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. Viper’s Notes On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million (the “Viper Notes”). Viper received gross proceeds of $500 million from the such offering, which it loaned to Viper LLC. The Viper Notes were issued under an indenture, dated as of October 16, 2019, among Viper, as issuer, Viper LLC, as guarantor and Wells Fargo, as trustee (the “Viper Indenture”). Pursuant to the Viper Indenture and the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper Notes will mature on November 1, 2027. Viper LLC guarantees the Viper Notes pursuant to the Viper Indenture. Neither Diamondback Energy, Inc. nor any of its other subsidiaries guarantee the Viper Notes. The Viper Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Viper’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events. Rattler’s Credit Agreement In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo, as administrative agent, and a syndicate of banks, as lenders party thereto (the “Rattler credit agreement”). The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million . Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC and is secured by substantially all of the assets of Rattler LLC and the guarantors. As of March 31, 2020 , Rattler LLC had $451 million of outstanding borrowings and $149 million available for future borrowings under the Rattler credit agreement. The outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected by Rattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement). Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio. The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default or events of default exists. The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below: Financial Covenant Required Ratio Consolidated Total Leverage Ratio Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Rattler credit agreement) is applicable, then not greater than 5.25 to 1.00) Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Rattler credit agreement) is made Not greater than 3.50 to 1.00 Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) Not less than 2.50 to 1.00 For purposes of calculating the financial maintenance covenants prior to the fiscal quarter ending June 30, 2020, EBITDA (as defined in the Rattler credit agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters commencing with the fiscal quarter ending September 30, 2019. As of March 31, 2020 and December 31, 2019 , Rattler and Rattler LLC were in compliance with all financial maintenance covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control. Alliance with Obsidian Resources, L.L.C. Diamondback O&G LLC 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, 2020 and December 31, 2019 , CEMOF’s return related to this alliance was $55 million and $39 million , respectively. As of March 31, 2020 , thirteen joint wells have been drilled and completed. |
CAPITAL STOCK AND EARNINGS PER
CAPITAL STOCK AND EARNINGS PER SHARE | 3 Months Ended |
Mar. 31, 2020 | |
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, 2020 and March 31, 2019 . Rattler’s Initial Public Offering Please see Note 5 —Rattler Midstream LP for information regarding the Rattler Offering. 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. 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. During the three months ended March 31, 2020 , the Company repurchased approximately $98 million of common stock under this repurchase program. As of March 31, 2020 , $1.3 billion remained available for use to repurchase shares under the Company's common stock repurchase program, although the Company has suspended this program to preserve liquidity. Earnings Per Share The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of Viper are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Three Months Ended March 31, 2020 2019 ($ in millions, except per share amounts, shares in thousands) Net (loss) income attributable to common stock $ (272 ) $ 10 Weighted average common shares outstanding: Basic weighted average common units outstanding 158,291 164,852 Effect of dilutive securities: Potential common shares issuable 203 209 Diluted weighted average common shares outstanding 158,494 165,061 Basic net (loss) income attributable to common stock $ (1.72 ) $ 0.06 Diluted net (loss) income attributable to common stock $ (1.72 ) $ 0.06 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, 2020 2019 (in thousands) Restricted stock units 318 31 |
EQUITY-BASED COMPENSATION
EQUITY-BASED COMPENSATION | 3 Months Ended |
Mar. 31, 2020 | |
Share-based Payment Arrangement [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, 2020 2019 (in millions) General and administrative expenses $ 9 $ 14 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties 6 6 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, 2020 : Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2019 505,867 $ 96.01 Granted 159,116 $ 62.82 Vested (104,640 ) $ 80.75 Forfeited (13,610 ) $ 99.72 Unvested at March 31, 2020 546,733 $ 89.18 The aggregate fair value of restricted stock units that vested during the three months ended March 31, 2020 and 2019 was $8 million and $13 million , respectively. As of March 31, 2020 , the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $38 million . Such cost is expected to be recognized over a weighted-average period of 2.1 years . During the three months ended March 31, 2020 , the Company modified certain of the restricted stock units to include dividend equivalent rights during the vesting period. This modification effected 765 awards and resulted in no incremental compensation costs to be recognized. 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 2020, eligible employees received performance restricted stock unit awards totaling 225,047 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, 2020 to December 31, 2022 and cliff vest at December 31, 2022. 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 2020 awards. 2020 Grant-date fair value $ 70.17 Risk-free rate 0.86 % Company volatility 36.70 % The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the three months ended March 31, 2020 : Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2019 271,819 $ 147.07 Granted 272,601 $ 85.73 Vested (47,554 ) $ 89.27 Forfeited (8,396 ) $ 170.45 Unvested at March 31, 2020 (1) 488,470 $ 110.33 (1) A maximum of 976,940 units could be awarded based upon the Company’s final TSR ranking. As of March 31, 2020 , the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $35 million . Such cost is expected to be recognized over a weighted-average period of 2.5 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, 2020 : Shares Weighted Average Exercise Price Outstanding at December 31, 2019 42,547 $ 90.89 Exercised (4,213 ) $ 72.67 Expired (970 ) $ 72.48 Outstanding at March 31, 2020 37,364 $ 93.42 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, 2019 216,343 $ 89.90 Exercised (11,338 ) $ 72.48 Outstanding at March 31, 2020 205,005 $ 91.58 1.51 $ — Vested and Expected to vest at March 31, 2020 205,005 $ 91.58 1.51 $ — Exercisable at March 31, 2020 205,005 $ 91.58 1.51 $ — Viper Phantom Units Under the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. Viper estimates the fair value of phantom units as the closing price of Viper’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 Viper for each phantom unit. The following table presents the phantom unit activity under the Viper LTIP for the three months ended March 31, 2020 : Phantom Units Weighted Average Grant-Date Unvested at December 31, 2019 95,248 $ 26.87 Vested (42,814 ) $ 23.24 Unvested at March 31, 2020 52,434 $ 29.83 The aggregate fair value of phantom units that vested during the three months ended March 31, 2020 was $1 million . As of March 31, 2020 , the unrecognized compensation cost related to unvested phantom units was $1 million . Such cost is expected to be recognized over a weighted-average period of 1.4 years . During the three months ended March 31, 2020 , the Partnership modified certain of the Phantom Units to include distribution equivalent rights during the vesting period. This modification effected 21 awards and resulted in no incremental compensation costs to be recognized. Rattler Long-Term Incentive Plan On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”), for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units as the closing price of Rattler’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 to one common unit of Rattler for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date. The following table presents the phantom unit activity under the Rattler LTIP for the three months ended March 31, 2020 : Phantom Weighted Average Unvested at December 31, 2019 2,226,895 $ 19.14 Granted 20,910 $ 13.85 Forfeited (569 ) $ 15.57 Unvested at March 31, 2020 2,247,236 $ 19.09 As of March 31, 2020 , the unrecognized compensation cost related to unvested phantom units was $36 million . Such cost is expected to be recognized over a weighted-average period of 4.1 years . |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 3 Months Ended |
Mar. 31, 2020 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS Lease Bonus - Viper During the three months ended March 31, 2020 , the Company paid Viper $0.3 million in lease bonus payments to extend the term of one lease and $1.3 million in lease bonus payments for one new lease. During the three months ended March 31, 2019 , the Company’s lease bonus payments to Viper were immaterial. Rattler Offering Please see Note 5 —Rattler Midstream LP for information regarding relationships between the Company and Rattler. |
INCOME TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The Company’s effective income tax rates were (26.1)% and (301.7)% for the three months ended March 31, 2020 and 2019 , respectively. Total income tax expense from continuing operations for the three months ended March 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss primarily due to (i) the impact of recording a valuation allowance on Viper’s deferred tax assets, (ii) state income taxes and (iii) the impact of permanent differences between book and taxable income, partially offset by tax benefit resulting from the anticipated carryback of federal net operating losses. For the three months ended March 31, 2020 , the Company recorded a discrete income tax expense of $143 million related to application of a valuation allowance on Viper’s beginning-of-year deferred tax assets, which consist primarily of its investment in Viper LLC and federal net operating loss carryforwards. A valuation allowance was also applied against the year-to-date tax benefit resulting from Viper’s projected pre-tax loss for 2020 . The determination to record a valuation allowance was based on management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets. In light of negative evidence including Viper’s recent cumulative losses projected for the year ending December 31, 2020, and the criteria established by applicable GAAP for recognizing the tax benefit of deferred tax assets, management’s assessment resulted in recording a valuation allowance against Viper’s deferred tax assets as of March 31, 2020. In addition, for the three months ended March 31, 2020 , the Company recorded a discrete income tax benefit of $25 million related to the available carryback of certain federal net operating losses to tax year(s) in which the corporate income tax rate was 35%. Prior to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) in the first quarter of 2020, there was no tax refund available to the Company with respect to its losses, resulting in deferred tax benefit associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate. Total income tax expense for the three months ended March 31, 2019 differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to (i) the revision of estimated deferred taxes recognized by Viper as a result of its change in tax status, (ii) state income taxes and (iii) the impact of permanent differences between book and taxable income. Based on information available as of March 31, 2019 regarding unitholders’ tax basis, Viper revised its estimate of deferred taxes on Viper’s investment in Viper LLC on the date of the tax status change, resulting in discrete deferred tax benefit of $35 million for the three months ended March 31, 2019. The CARES Act was enacted on March 27, 2020. This legislation included a number of provisions applicable to U.S. income taxes for corporations, including providing for carryback of certain net operating losses, accelerated refund of minimum tax credits, and modifications to the rules limiting the deductibility of business interest expense. The Company has considered the impact of this legislation in the period of enactment, resulting in discrete income tax benefit for the three months ended March 31, 2020 related to the anticipated carryback of approximately $179 million of the Company’s federal net operating losses as noted above. As a result of the refund associated with such carryback as well as the accelerated refund available for minimum tax credits, the Company’s current federal taxes receivable total approximately $101 million as of March 31, 2020. As discussed further in Note 5 , on May 28, 2019, Rattler completed its initial public offering. Even though Rattler is organized as a limited partnership under state law, Rattler is subject to U.S. federal and state income tax at corporate rates, subsequent to the effective date of Rattler’s election to be treated as a corporation for U.S. federal income tax purposes. As such, Rattler’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest. |
DERIVATIVES
DERIVATIVES | 3 Months Ended |
Mar. 31, 2020 | |
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.” Diamondback Commodity Contracts The Company has used fixed price swap contracts, fixed price basis swap contracts, double-up 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. The Company also utilizes double-up swap contracts for a portion of its natural gas sales. These contracts include a traditional fixed price swap in addition to a call option at the same quantity and price, providing the counterparty the option to double the volume in the swap contract should the monthly settlement price exceed the fixed price contracted upon. 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 and Waha Hub pricing, liquids derivative settlements based on Mt. Belvieu pricing and diesel fuel settlements based on Gulf Coast ultra low sulfur diesel 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, 2020 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 2021 Volume (Bbls/MMBtu/Gallons) Fixed Price Swap (per Bbl/MMBtu/Gallon) Volume (Bbls/MMBtu/Gallons) Fixed Price Swap (per Bbl/MMBtu/Gallon) Oil Swaps - WTI Cushing 3,114,000 $ 46.33 — $ — Oil Swaps - WTI Magellan East Houston 1,100,000 $ 61.95 1,825,000 $ 37.78 Oil Swaps - BRENT 7,292,000 $ 48.80 3,816,000 $ 43.26 Oil Swaption - BRENT — $ — 2,024,000 $ 44.77 Oil Basis Swaps - WTI Cushing 11,125,000 $ (1.21 ) — $ — Oil Rolling Hedge - WTI Cushing 5,500,000 $ 0.44 — $ — Natural Gas Swaps - Henry Hub 8,190,000 $ 2.55 14,600,000 $ 2.47 Natural Gas Swaps - Waha Hub 16,500,000 $ 1.51 — $ — Natural Gas Basis Swaps - Waha Hub 33,000,000 $ (1.46 ) 62,050,000 $ (0.71 ) Diesel Price Swaps 275,000,000 $ 1.60 — $ — Oil Swaption - WTI Magellan East Houston 2020 Volume (Bbl) 2,750,000 Swap price (per Bbl) $ 55.00 Put price (per Bbl) $ 40.00 Oil Options - WTI Cushing 2020 Volume (Bbl) 1,292,500 Long Put Price (per Bbl) $ 46.51 Oil Put Spread - WTI Magellan East Houston 2020 Volume (Bbl) 1,045,000 Floor price (per Bbl) $ 50.00 Short Put price (per Bbl) $ 25.00 Gas Swap Double-Up - Waha Hub 2020 Volume (Mcf) 8,250,000 Swap price (per Mcf) $ 1.70 Option price (per Mcf) $ 1.70 2020 2021 Oil Costless Collars WTI Cushing Brent WTI Magellan East Houston Brent Volume (Bbls) 10,182,975 17,750,750 1,092,000 21,717,500 Floor price (per Bbl) $ 38.10 $ 37.64 $ 39.00 $ 39.45 Ceiling price (per Bbl) $ 45.02 $ 46.66 $ 49.00 $ 48.16 Interest Rate Swaps and Treasury Locks The Company has used interest rate swaps and treasury locks to reduce the Company’s exposure to variable rate interest payments associated with the Company’s revolving credit facility. The interest rate swaps and treasury locks have not been designated as hedging instruments and as a result, the Company recognizes all changes in fair value immediately in earnings. The following table summarizes the Company’s interest rate swaps and treasury locks as of March 31, 2020 : Type Effective Date Termination Date Notional Amount (in millions) Interest Rate Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.551 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.5575 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.297 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.195 % Viper Commodity Contracts Viper uses fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. With respect to Viper’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to Viper if the settlement price for any settlement period is less than the swap or basis price, and Viper 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. Viper has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. Under Viper’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to Viper and when the settlement price is above the ceiling price, Viper is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required. Viper’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 Midland-Cushing) and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub and Waha Hub pricing. By using derivative instruments to economically hedge exposure to changes in commodity prices, Viper 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 Viper, which creates credit risk. Viper’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, Viper is not required to post any collateral. Viper does not require collateral from its counterparties. Viper 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, 2020 , Viper had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 Swaps Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 275,000 $ 27.45 Oil Basis Swaps - WTI (Midland-Cushing) 1,100,000 $ (2.60 ) Natural Gas Basis Swaps - Waha Hub 6,875,000 $ (2.07 ) Collars - WTI (Cushing) 2020 2021 Volume (Bbls) 3,850,000 3,650,000 Floor price (per Bbl) $ 28.86 $ 30.00 Ceiling price (per Bbl) $ 32.33 $ 43.05 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, 2020 and December 31, 2019 : March 31, 2020 December 31, 2019 (in millions) Gross amounts of assets presented in the Consolidated Balance Sheet $ 818 $ 71 Amounts netted in the Consolidated Balance Sheet (254 ) (18 ) Net amounts of assets presented in the Consolidated Balance Sheet $ 564 $ 53 Gross amounts of liabilities presented in the Consolidated Balance Sheet $ 336 $ 45 Amounts netted in the Consolidated Balance Sheet (254 ) (18 ) Net amounts of liabilities presented in the Consolidated Balance Sheet $ 82 $ 27 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, 2020 December 31, 2019 (in millions) Current assets: derivative instruments $ 534 $ 46 Noncurrent assets: derivative instruments 30 7 Total assets $ 564 $ 53 Current liabilities: derivative instruments $ 16 $ 27 Noncurrent liabilities: derivative instruments 66 — Total liabilities $ 82 $ 27 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, 2020 2019 (in millions) Change in fair value of open non-hedge derivative instruments Commodity contracts $ 517 $ (285 ) Interest rate swaps (62 ) — Total $ 455 $ (285 ) Gain on settlement of non-hedge derivative instruments Commodity contracts 87 17 Total $ 87 $ 17 Gain (loss) on derivative instruments, net $ 542 $ (268 ) |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 3 Months Ended |
Mar. 31, 2020 | |
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 FASB issued ASC 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 Viper’s cost method investment. The fair value of Viper’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, 2020 and December 31, 2019 : March 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in millions) Assets: Investment $ 9 $ — $ — $ 19 $ — $ — Derivative Instruments — 564 — — 53 — Liabilities: Derivative Instruments $ — $ 82 $ — $ — $ 27 $ — 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, 2020 December 31, 2019 Carrying Carrying Amount Fair Value Amount Fair Value (in millions) Debt: Revolving credit facility $ 199 $ 199 $ 13 $ 13 4.625% Notes due 2021 $ 399 $ 369 $ 399 $ 411 7.320% Medium-term Notes, Series A, due 2022 $ 21 $ 19 $ 21 $ 22 2.875% Senior Notes due 2024 (1) $ 992 $ 720 $ 992 $ 1,012 5.375% Senior Notes due 2025 (1) $ 799 $ 587 $ 799 $ 840 3.250% Senior Notes due 2026 (1) $ 792 $ 568 $ 792 $ 812 7.350% Medium-term Notes, Series A, due 2027 $ 11 $ 9 $ 11 $ 12 7.125% Medium-term Notes, Series B, due 2028 $ 107 $ 67 $ 108 $ 116 3.500 Senior Notes due 2029 (1) $ 1,187 $ 851 $ 1,186 $ 1,226 Viper revolving credit facility $ 174 $ 174 $ 97 $ 97 Viper's 5.375% Senior Notes due 2027 $ 490 $ 420 $ 490 $ 521 Rattler revolving credit facility $ 451 $ 451 $ 424 $ 424 DrillCo Agreement $ 55 $ 55 $ 39 $ 39 (1) The carrying value includes associated deferred loan costs and any discount. The fair value of the revolving credit facility, the Viper credit agreement and the Rattler credit agreement 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, 2020 quoted market price, a Level 1 classification in the fair value hierarchy. |
LEASES
LEASES | 3 Months Ended |
Mar. 31, 2020 | |
Leases [Abstract] | |
LEASES | LEASES The Company leases certain drilling rigs, facilities, compression and other equipment. 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 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, 2020 and 2019 : Three Months Ended March 31, 2020 2019 (in millions) Operating lease costs $ 5 $ 4 For the three months ended March 31, 2020 and 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 and $5 million , respectively. During the three months ended March 31, 2020 , 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 accrued liabilities and other long-term liabilities, respectively, on the Condensed Consolidated Balance Sheet. As of March 31, 2020 , the operating right-of-use assets were $18 million and operating lease liabilities were $18 million , of which $12 million was classified as current. As of March 31, 2020 , the weighted average remaining lease term was 1.8 years and the weighted average discount rate was 9.3% . 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, 2020 : As of March 31, 2020 (in millions) 2020 $ 11 2021 6 2022 3 2023 — 2024 — Thereafter — Total lease payments 20 Less: interest 2 Present value of lease liabilities $ 18 For leases in which the Company is the lessor, the Company (i) retained classification of our historical leases as we are not required to reassess classification upon adoption of the new standard, (ii) expensed indirect leasing costs in connection with new or extended tenant leases, the recognition of which would have been deferred under prior accounting guidance and (iii) aggregated revenue from our lease components and non-lease components (comprised of tenant expense reimbursements) into revenue from rental properties. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended |
Mar. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES The Company is a party to various legal proceedings, disputes and claims arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, cash flows or results of operations. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 3 Months Ended |
Mar. 31, 2020 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENTS First Quarter 2020 Dividend Declaration On May 1, 2020 , the Board of Directors of the Company declared a cash dividend for the first quarter of 2020 of $0.3750 per share of common stock, payable on May 21, 2020 to its stockholders of record at the close of business on May 14, 2020 . Viper Credit Agreement In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent under the Viper Credit Agreement recommended that the borrowing base be decreased under the Viper credit agreement to $580 million effective mid-May 2020. The decrease is subject to approval by the requisite lenders under the Viper credit agreement. Under the new expected borrowing base, Viper LLC would have had $407 million of availability for future borrowings under the Viper credit agreement as of March 31, 2020 . Commodity Contracts Subsequent to March 31, 2020 , 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 Crude Oil Brent. The following tables present the derivative contracts entered into by the Company subsequent to March 31, 2020 . When aggregating multiple contracts, the weighted average contract price is disclosed. March 2020 - December 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Rolling Hedge - WTI 27,500,000 (1.35 ) Natural Gas Swaps - Henry Hub 5,520,000 $ 2.40 Oil Basis Swaps - WTI Midland 1,712,000 $ (1.31 ) January 2021 - December 2021 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Natural Gas Swaps - Henry Hub 29,200,000 2.62 Natural Gas Swaps - Waha Hub 1,095,000 0.70 Natural Gas Basis Swaps - Waha Hub 10,950,000 (0.56 ) January 2021 - December 2021 Oil Costless Collar WTI Volume (Bbls) 730,000 Floor price (per Bbl) $ 25.00 Ceiling price (per Bbl) $ 38.40 Current Commodity Environment Oil prices dropped sharply in early March 2020, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of the changes in oil and natural gas production, inventories and industry demand, as well as national and international economic performance. The Company cannot predict when prices will improve and stabilize. |
REPORT OF BUSINESS SEGMENTS
REPORT OF BUSINESS SEGMENTS | 3 Months Ended |
Mar. 31, 2020 | |
Segment Reporting [Abstract] | |
REPORT OF BUSINESS SEGMENTS | BUSINESS SEGMENTS The Company reports its operations in two business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas and (ii) the midstream operations segment includes midstream services and real estate. All of Rattler’s equity method investments are included in the midstream segment. The following tables summarize the results of the Company's business segments during the periods presented: Upstream Midstream Services Eliminations Total Three Months Ended March 31, 2020: (in millions) Third-party revenues $ 883 $ 16 $ — $ 899 Intersegment revenues — 113 (113 ) — Total revenues 883 129 (113 ) 899 Depreciation, depletion and amortization 394 13 — 407 Impairment of oil and natural gas properties 1,009 — — 1,009 (Loss) income from operations (782 ) 61 (81 ) (802 ) Interest expense, net (45 ) (3 ) — (48 ) Other income (expense) 489 (3 ) (1 ) 485 Provision for income taxes 79 4 — 83 Net (loss) income attributable to non-controlling interest (128 ) 41 (41 ) (128 ) Net (loss) income attributable to Diamondback Energy (244 ) 13 (41 ) (272 ) As of March 31, 2020: Total assets $ 21,875 $ 1,676 $ (165 ) $ 23,386 Upstream Midstream Services Eliminations Total Three Months Ended March 31, 2019: (in millions) Third-party revenues $ 843 $ 21 $ — $ 864 Intersegment revenues — 74 (74 ) — Total revenues 843 95 (74 ) 864 Depreciation, depletion and amortization 312 10 — 322 Income from operations 300 50 (31 ) 319 Interest expense, net (46 ) — — (46 ) Other income (expense) (308 ) — (1 ) (309 ) Provision for (benefit from) income taxes (44 ) 11 — (33 ) Net income attributable to non-controlling interest 33 — — 33 Net income attributable to Diamondback Energy 3 39 (32 ) 10 As of December 31, 2019: Total assets $ 22,125 $ 1,636 $ (230 ) $ 23,531 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2020 | |
Accounting Policies [Abstract] | |
Basis of Presentation | 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. |
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. Making accurate estimates and assumptions are particularly difficult as the oil and gas industry experiences challenges resulting from negative pricing pressure from the effects of a decline in worldwide economic conditions. The decline in worldwide economic conditions is the result of a global COVID-19 pandemic announced in March 2020, which has reduced economic activity and resulted in a significant decline in the short term demand for oil and gas production. Companies in the oil and gas industry are beginning to change near term business plans in response to changing market conditions. The aforementioned circumstances generally increases the estimation uncertainty in our accounting estimates, particularly the accounting estimates involving financial forecasts. 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 derivative instruments and estimates of income taxes. |
Accounts Receivable | Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date. The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. The adoption of ASU 2016-13 did not result in a material change to the Company’s allowance. At March 31, 2020 , the Company recorded an allowance for doubtful accounts of $1 million related to joint interest and other receivables and $1 million related to oil and natural gas sales receivables. |
New Accounting Pronouncements | Recent Accounting Pronouncements The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements: Standard Description Date of Adoption Effect on Financial Statements or Other Significant Matters Recently Adopted Pronouncements ASU 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. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses. ASU 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. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels. ASU 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. Q1 2020 The Company adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)” This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any cost method investments. ASU 2020-04, “Rate Reform (Topic 848)” This update provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference LIBOR. Q1 2020 The Company adopted this update upon issuance and elected to use the optional expedient for contracts and hedging that reference LIBOR. The amendments in this update expire on December 31, 2022. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. Pronouncements Not Yet Adopted ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes” This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance. Q1 2021 This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity. |
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 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 ASC 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, 2020 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded. |
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. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. |
REAL ESTATE ASSETS (Tables)
REAL ESTATE ASSETS (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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, 2020 December 31, 2019 (Years) (in millions) Buildings 20-30 $ 102 $ 102 Tenant improvements 15 5 5 Land N/A 2 2 Land improvements 15 1 1 Total real estate assets 110 110 Less: accumulated depreciation (10 ) (9 ) Total investment in land and buildings, net $ 100 $ 101 Weighted Average Useful Lives March 31, 2020 December 31, 2019 (Months) (in millions) In-place lease intangibles 45 $ 11 $ 11 Less: accumulated amortization (6 ) (6 ) In-place lease intangibles, net 5 5 Above-market lease intangibles 45 3 4 Less: accumulated amortization (1 ) (1 ) Above-market lease intangibles, net 2 3 Total intangible lease assets, net $ 7 $ 8 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
Schedule of property and equipment | Property and equipment includes the following as of the dates indicated: March 31, December 31, 2020 2019 (in millions) Oil and natural gas properties: Subject to depletion $ 18,231 $ 16,575 Not subject to depletion 8,488 9,207 Gross oil and natural gas properties 26,719 25,782 Accumulated depletion (3,387 ) (2,995 ) Accumulated impairment (2,943 ) (1,934 ) Oil and natural gas properties, net 20,389 20,853 Midstream assets 987 931 Other property, equipment and land 130 125 Accumulated depreciation (86 ) (74 ) Total property and equipment, net $ 21,420 $ 21,835 Balance of costs not subject to depletion: Incurred in 2020 $ 59 Incurred in 2019 604 Incurred in 2018 5,398 Incurred in 2017 2,124 Incurred in 2016 303 Total not subject to depletion $ 8,488 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Asset Retirement Obligation [Abstract] | |
Asset retirement obligations | The following table describes the changes to the Company’s asset retirement obligations liability for the following periods: Three Months Ended March 31, 2020 2019 (in millions) Asset retirement obligations, beginning of period $ 94 $ 136 Additional liabilities incurred 4 1 Liabilities acquired — 3 Liabilities settled — (2 ) Accretion expense 2 2 Revisions in estimated liabilities — — Asset retirement obligations, end of period 100 140 Less current portion 1 — Asset retirement obligations - long-term $ 99 $ 140 |
EQUITY METHOD INVESTMENTS (Tabl
EQUITY METHOD INVESTMENTS (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | as of the dates indicated: Ownership Interest March 31, 2020 December 31, 2019 (in millions) EPIC Crude Holdings, LP 10 % $ 117 $ 109 Gray Oak Pipeline, LLC 10 % 122 116 Wink to Webster Pipeline LLC 4 % 45 34 OMOG JV LLC 60 % 216 219 Amarillo Rattler, LLC 50 % 2 1 $ 502 $ 479 |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt | Long-term debt consisted of the following as of the dates indicated: March 31, December 31, 2020 2019 (in millions) 4.625% Notes due 2021 $ 400 $ 399 7.320% Medium-term Notes, Series A, due 2022 20 21 2.875% Senior Notes due 2024 1,000 1,000 5.375% Senior Notes due 2025 800 800 3.250% Senior Notes due 2026 800 800 7.350% Medium-term Notes, Series A, due 2027 10 11 7.125% Medium-term Notes, Series B, due 2028 100 108 3.500% Senior Notes due 2029 1,200 1,200 DrillCo Agreement 55 39 Unamortized debt issuance costs (19 ) (19 ) Unamortized discount costs (31 ) (31 ) Unamortized premium costs 18 9 Revolving credit facility 199 13 Viper revolving credit facility 174 97 Viper 5.375% Senior Notes due 2027 500 500 Rattler revolving credit facility 451 424 Total long-term debt $ 5,677 $ 5,371 |
Financial covenants | These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, purchases of margin stock 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 Viper credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined the Viper credit agreement Not less than 1.0 to 1.0 The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below: Financial Covenant Required Ratio Consolidated Total Leverage Ratio Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Rattler credit agreement) is applicable, then not greater than 5.25 to 1.00) Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Rattler credit agreement) is made Not greater than 3.50 to 1.00 Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) Not less than 2.50 to 1.00 |
Capital Stock and Earnings Pe_2
Capital Stock and Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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, 2020 2019 ($ in millions, except per share amounts, shares in thousands) Net (loss) income attributable to common stock $ (272 ) $ 10 Weighted average common shares outstanding: Basic weighted average common units outstanding 158,291 164,852 Effect of dilutive securities: Potential common shares issuable 203 209 Diluted weighted average common shares outstanding 158,494 165,061 Basic net (loss) income attributable to common stock $ (1.72 ) $ 0.06 Diluted net (loss) income attributable to common stock $ (1.72 ) $ 0.06 |
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, 2020 2019 (in thousands) Restricted stock units 318 31 |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Share-based Payment Arrangement [Abstract] | |
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, 2020 2019 (in millions) General and administrative expenses $ 9 $ 14 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties 6 6 |
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, 2020 : Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2019 505,867 $ 96.01 Granted 159,116 $ 62.82 Vested (104,640 ) $ 80.75 Forfeited (13,610 ) $ 99.72 Unvested at March 31, 2020 546,733 $ 89.18 |
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 2020 awards. 2020 Grant-date fair value $ 70.17 Risk-free rate 0.86 % Company volatility 36.70 % |
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, 2020 : Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2019 271,819 $ 147.07 Granted 272,601 $ 85.73 Vested (47,554 ) $ 89.27 Forfeited (8,396 ) $ 170.45 Unvested at March 31, 2020 (1) 488,470 $ 110.33 (1) A maximum of 976,940 units could be awarded based upon the Company’s final TSR ranking. |
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, 2020 : Shares Weighted Average Exercise Price Outstanding at December 31, 2019 42,547 $ 90.89 Exercised (4,213 ) $ 72.67 Expired (970 ) $ 72.48 Outstanding at March 31, 2020 37,364 $ 93.42 |
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, 2019 216,343 $ 89.90 Exercised (11,338 ) $ 72.48 Outstanding at March 31, 2020 205,005 $ 91.58 1.51 $ — Vested and Expected to vest at March 31, 2020 205,005 $ 91.58 1.51 $ — Exercisable at March 31, 2020 205,005 $ 91.58 1.51 $ — |
Phantom units activity | The following table presents the phantom unit activity under the Viper LTIP for the three months ended March 31, 2020 : Phantom Units Weighted Average Grant-Date Unvested at December 31, 2019 95,248 $ 26.87 Vested (42,814 ) $ 23.24 Unvested at March 31, 2020 52,434 $ 29.83 The following table presents the phantom unit activity under the Rattler LTIP for the three months ended March 31, 2020 : Phantom Weighted Average Unvested at December 31, 2019 2,226,895 $ 19.14 Granted 20,910 $ 13.85 Forfeited (569 ) $ 15.57 Unvested at March 31, 2020 2,247,236 $ 19.09 |
Derivatives (Tables)
Derivatives (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative contracts | As of March 31, 2020 , Viper had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 Swaps Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 275,000 $ 27.45 Oil Basis Swaps - WTI (Midland-Cushing) 1,100,000 $ (2.60 ) Natural Gas Basis Swaps - Waha Hub 6,875,000 $ (2.07 ) Collars - WTI (Cushing) 2020 2021 Volume (Bbls) 3,850,000 3,650,000 Floor price (per Bbl) $ 28.86 $ 30.00 Ceiling price (per Bbl) $ 32.33 $ 43.05 As of March 31, 2020 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 2021 Volume (Bbls/MMBtu/Gallons) Fixed Price Swap (per Bbl/MMBtu/Gallon) Volume (Bbls/MMBtu/Gallons) Fixed Price Swap (per Bbl/MMBtu/Gallon) Oil Swaps - WTI Cushing 3,114,000 $ 46.33 — $ — Oil Swaps - WTI Magellan East Houston 1,100,000 $ 61.95 1,825,000 $ 37.78 Oil Swaps - BRENT 7,292,000 $ 48.80 3,816,000 $ 43.26 Oil Swaption - BRENT — $ — 2,024,000 $ 44.77 Oil Basis Swaps - WTI Cushing 11,125,000 $ (1.21 ) — $ — Oil Rolling Hedge - WTI Cushing 5,500,000 $ 0.44 — $ — Natural Gas Swaps - Henry Hub 8,190,000 $ 2.55 14,600,000 $ 2.47 Natural Gas Swaps - Waha Hub 16,500,000 $ 1.51 — $ — Natural Gas Basis Swaps - Waha Hub 33,000,000 $ (1.46 ) 62,050,000 $ (0.71 ) Diesel Price Swaps 275,000,000 $ 1.60 — $ — Oil Swaption - WTI Magellan East Houston 2020 Volume (Bbl) 2,750,000 Swap price (per Bbl) $ 55.00 Put price (per Bbl) $ 40.00 Oil Options - WTI Cushing 2020 Volume (Bbl) 1,292,500 Long Put Price (per Bbl) $ 46.51 Oil Put Spread - WTI Magellan East Houston 2020 Volume (Bbl) 1,045,000 Floor price (per Bbl) $ 50.00 Short Put price (per Bbl) $ 25.00 Gas Swap Double-Up - Waha Hub 2020 Volume (Mcf) 8,250,000 Swap price (per Mcf) $ 1.70 Option price (per Mcf) $ 1.70 2020 2021 Oil Costless Collars WTI Cushing Brent WTI Magellan East Houston Brent Volume (Bbls) 10,182,975 17,750,750 1,092,000 21,717,500 Floor price (per Bbl) $ 38.10 $ 37.64 $ 39.00 $ 39.45 Ceiling price (per Bbl) $ 45.02 $ 46.66 $ 49.00 $ 48.16 The following table summarizes the Company’s interest rate swaps and treasury locks as of March 31, 2020 : Type Effective Date Termination Date Notional Amount (in millions) Interest Rate Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.551 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.5575 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.297 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.195 % The following tables present the derivative contracts entered into by the Company subsequent to March 31, 2020 . When aggregating multiple contracts, the weighted average contract price is disclosed. March 2020 - December 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Rolling Hedge - WTI 27,500,000 (1.35 ) Natural Gas Swaps - Henry Hub 5,520,000 $ 2.40 Oil Basis Swaps - WTI Midland 1,712,000 $ (1.31 ) January 2021 - December 2021 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Natural Gas Swaps - Henry Hub 29,200,000 2.62 Natural Gas Swaps - Waha Hub 1,095,000 0.70 Natural Gas Basis Swaps - Waha Hub 10,950,000 (0.56 ) January 2021 - December 2021 Oil Costless Collar WTI Volume (Bbls) 730,000 Floor price (per Bbl) $ 25.00 Ceiling price (per Bbl) $ 38.40 |
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, 2020 and December 31, 2019 : March 31, 2020 December 31, 2019 (in millions) Gross amounts of assets presented in the Consolidated Balance Sheet $ 818 $ 71 Amounts netted in the Consolidated Balance Sheet (254 ) (18 ) Net amounts of assets presented in the Consolidated Balance Sheet $ 564 $ 53 Gross amounts of liabilities presented in the Consolidated Balance Sheet $ 336 $ 45 Amounts netted in the Consolidated Balance Sheet (254 ) (18 ) Net amounts of liabilities presented in the Consolidated Balance Sheet $ 82 $ 27 |
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, 2020 December 31, 2019 (in millions) Current assets: derivative instruments $ 534 $ 46 Noncurrent assets: derivative instruments 30 7 Total assets $ 564 $ 53 Current liabilities: derivative instruments $ 16 $ 27 Noncurrent liabilities: derivative instruments 66 — Total liabilities $ 82 $ 27 |
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, 2020 2019 (in millions) Change in fair value of open non-hedge derivative instruments Commodity contracts $ 517 $ (285 ) Interest rate swaps (62 ) — Total $ 455 $ (285 ) Gain on settlement of non-hedge derivative instruments Commodity contracts 87 17 Total $ 87 $ 17 Gain (loss) on derivative instruments, net $ 542 $ (268 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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, 2020 and December 31, 2019 : March 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in millions) Assets: Investment $ 9 $ — $ — $ 19 $ — $ — Derivative Instruments — 564 — — 53 — Liabilities: Derivative Instruments $ — $ 82 $ — $ — $ 27 $ — |
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, 2020 December 31, 2019 Carrying Carrying Amount Fair Value Amount Fair Value (in millions) Debt: Revolving credit facility $ 199 $ 199 $ 13 $ 13 4.625% Notes due 2021 $ 399 $ 369 $ 399 $ 411 7.320% Medium-term Notes, Series A, due 2022 $ 21 $ 19 $ 21 $ 22 2.875% Senior Notes due 2024 (1) $ 992 $ 720 $ 992 $ 1,012 5.375% Senior Notes due 2025 (1) $ 799 $ 587 $ 799 $ 840 3.250% Senior Notes due 2026 (1) $ 792 $ 568 $ 792 $ 812 7.350% Medium-term Notes, Series A, due 2027 $ 11 $ 9 $ 11 $ 12 7.125% Medium-term Notes, Series B, due 2028 $ 107 $ 67 $ 108 $ 116 3.500 Senior Notes due 2029 (1) $ 1,187 $ 851 $ 1,186 $ 1,226 Viper revolving credit facility $ 174 $ 174 $ 97 $ 97 Viper's 5.375% Senior Notes due 2027 $ 490 $ 420 $ 490 $ 521 Rattler revolving credit facility $ 451 $ 451 $ 424 $ 424 DrillCo Agreement $ 55 $ 55 $ 39 $ 39 (1) The carrying value includes associated deferred loan costs and any discount. |
LEASES (Tables)
LEASES (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Leases [Abstract] | |
Schedule of operating lease costs | The following table summarizes operating lease costs for the three months ended March 31, 2020 and 2019 : Three Months Ended March 31, 2020 2019 (in millions) Operating lease costs $ 5 $ 4 |
Schedule of undiscounted cash flows owned by company to lessors pursuant to contractual agreements | 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, 2020 : As of March 31, 2020 (in millions) 2020 $ 11 2021 6 2022 3 2023 — 2024 — Thereafter — Total lease payments 20 Less: interest 2 Present value of lease liabilities $ 18 |
SUBSEQUENT EVENTS (Tables)
SUBSEQUENT EVENTS (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Subsequent Events [Abstract] | |
Schedule of derivative contracts by Company subsequent aggregating weighted average contract | As of March 31, 2020 , Viper had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 Swaps Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 275,000 $ 27.45 Oil Basis Swaps - WTI (Midland-Cushing) 1,100,000 $ (2.60 ) Natural Gas Basis Swaps - Waha Hub 6,875,000 $ (2.07 ) Collars - WTI (Cushing) 2020 2021 Volume (Bbls) 3,850,000 3,650,000 Floor price (per Bbl) $ 28.86 $ 30.00 Ceiling price (per Bbl) $ 32.33 $ 43.05 As of March 31, 2020 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 2021 Volume (Bbls/MMBtu/Gallons) Fixed Price Swap (per Bbl/MMBtu/Gallon) Volume (Bbls/MMBtu/Gallons) Fixed Price Swap (per Bbl/MMBtu/Gallon) Oil Swaps - WTI Cushing 3,114,000 $ 46.33 — $ — Oil Swaps - WTI Magellan East Houston 1,100,000 $ 61.95 1,825,000 $ 37.78 Oil Swaps - BRENT 7,292,000 $ 48.80 3,816,000 $ 43.26 Oil Swaption - BRENT — $ — 2,024,000 $ 44.77 Oil Basis Swaps - WTI Cushing 11,125,000 $ (1.21 ) — $ — Oil Rolling Hedge - WTI Cushing 5,500,000 $ 0.44 — $ — Natural Gas Swaps - Henry Hub 8,190,000 $ 2.55 14,600,000 $ 2.47 Natural Gas Swaps - Waha Hub 16,500,000 $ 1.51 — $ — Natural Gas Basis Swaps - Waha Hub 33,000,000 $ (1.46 ) 62,050,000 $ (0.71 ) Diesel Price Swaps 275,000,000 $ 1.60 — $ — Oil Swaption - WTI Magellan East Houston 2020 Volume (Bbl) 2,750,000 Swap price (per Bbl) $ 55.00 Put price (per Bbl) $ 40.00 Oil Options - WTI Cushing 2020 Volume (Bbl) 1,292,500 Long Put Price (per Bbl) $ 46.51 Oil Put Spread - WTI Magellan East Houston 2020 Volume (Bbl) 1,045,000 Floor price (per Bbl) $ 50.00 Short Put price (per Bbl) $ 25.00 Gas Swap Double-Up - Waha Hub 2020 Volume (Mcf) 8,250,000 Swap price (per Mcf) $ 1.70 Option price (per Mcf) $ 1.70 2020 2021 Oil Costless Collars WTI Cushing Brent WTI Magellan East Houston Brent Volume (Bbls) 10,182,975 17,750,750 1,092,000 21,717,500 Floor price (per Bbl) $ 38.10 $ 37.64 $ 39.00 $ 39.45 Ceiling price (per Bbl) $ 45.02 $ 46.66 $ 49.00 $ 48.16 The following table summarizes the Company’s interest rate swaps and treasury locks as of March 31, 2020 : Type Effective Date Termination Date Notional Amount (in millions) Interest Rate Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.551 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.5575 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.297 % Interest Rate Swap December 31, 2020 December 31, 2030 $ 250 1.195 % The following tables present the derivative contracts entered into by the Company subsequent to March 31, 2020 . When aggregating multiple contracts, the weighted average contract price is disclosed. March 2020 - December 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Rolling Hedge - WTI 27,500,000 (1.35 ) Natural Gas Swaps - Henry Hub 5,520,000 $ 2.40 Oil Basis Swaps - WTI Midland 1,712,000 $ (1.31 ) January 2021 - December 2021 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Natural Gas Swaps - Henry Hub 29,200,000 2.62 Natural Gas Swaps - Waha Hub 1,095,000 0.70 Natural Gas Basis Swaps - Waha Hub 10,950,000 (0.56 ) January 2021 - December 2021 Oil Costless Collar WTI Volume (Bbls) 730,000 Floor price (per Bbl) $ 25.00 Ceiling price (per Bbl) $ 38.40 |
REPORT OF BUSINESS SEGMENTS (Ta
REPORT OF BUSINESS SEGMENTS (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Segment Reporting [Abstract] | |
Results of the company business segments | The following tables summarize the results of the Company's business segments during the periods presented: Upstream Midstream Services Eliminations Total Three Months Ended March 31, 2020: (in millions) Third-party revenues $ 883 $ 16 $ — $ 899 Intersegment revenues — 113 (113 ) — Total revenues 883 129 (113 ) 899 Depreciation, depletion and amortization 394 13 — 407 Impairment of oil and natural gas properties 1,009 — — 1,009 (Loss) income from operations (782 ) 61 (81 ) (802 ) Interest expense, net (45 ) (3 ) — (48 ) Other income (expense) 489 (3 ) (1 ) 485 Provision for income taxes 79 4 — 83 Net (loss) income attributable to non-controlling interest (128 ) 41 (41 ) (128 ) Net (loss) income attributable to Diamondback Energy (244 ) 13 (41 ) (272 ) As of March 31, 2020: Total assets $ 21,875 $ 1,676 $ (165 ) $ 23,386 Upstream Midstream Services Eliminations Total Three Months Ended March 31, 2019: (in millions) Third-party revenues $ 843 $ 21 $ — $ 864 Intersegment revenues — 74 (74 ) — Total revenues 843 95 (74 ) 864 Depreciation, depletion and amortization 312 10 — 322 Income from operations 300 50 (31 ) 319 Interest expense, net (46 ) — — (46 ) Other income (expense) (308 ) — (1 ) (309 ) Provision for (benefit from) income taxes (44 ) 11 — (33 ) Net income attributable to non-controlling interest 33 — — 33 Net income attributable to Diamondback Energy 3 39 (32 ) 10 As of December 31, 2019: Total assets $ 22,125 $ 1,636 $ (230 ) $ 23,531 |
DESCRIPTION OF THE BUSINESS A_2
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION (Details) | Mar. 31, 2020 | May 28, 2019 |
Viper Energy Partners LP | ||
Noncontrolling Interest [Line Items] | ||
Ownership percentage | 58.00% | |
Rattler MIdstream LP | ||
Noncontrolling Interest [Line Items] | ||
Ownership percentage | 71.00% | 29.00% |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions | Mar. 31, 2020USD ($) |
Joint Interest and Other Receivables | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Allowance for doubtful accounts | $ 1 |
Oil and Natural Gas Sales Receivables | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Allowance for doubtful accounts | $ 1 |
REVENUE FROM CONTRACTS WITH C_2
REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) | 3 Months Ended |
Mar. 31, 2020 | |
Minimum | |
Disaggregation of Revenue [Line Items] | |
Revenue settlement period after production delivery | 30 days |
Maximum | |
Disaggregation of Revenue [Line Items] | |
Revenue settlement period after production delivery | 90 days |
VIPER ENERGY PARTNERS LP (Detai
VIPER ENERGY PARTNERS LP (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2020USD ($) | |
Viper Energy Partners LP | |
Noncontrolling Interest [Line Items] | |
Ownership percentage | 58.00% |
Viper Energy Partners LP | |
Noncontrolling Interest [Line Items] | |
Amount allocated by general partners per Partnership Agreement | $ 1 |
RATTLER MIDSTREAM LP (Details)
RATTLER MIDSTREAM LP (Details) - USD ($) $ / shares in Units, $ in Millions | May 28, 2019 | Mar. 31, 2020 | Mar. 31, 2019 |
Noncontrolling Interest [Line Items] | |||
Limited partners capital contribution | $ 1 | ||
Distribution to affiliates | $ 1 | $ 0 | |
Rattler MIdstream LP | |||
Noncontrolling Interest [Line Items] | |||
Ownership percentage | 29.00% | 71.00% | |
Limited partners ownership percentage | 71.00% | ||
Rattler MIdstream LP | |||
Noncontrolling Interest [Line Items] | |||
General partners cash contribution | $ 1 | ||
Percentage of preferred cash distribution received | 8.00% | ||
Rattler MIdstream LP | IPO | |||
Noncontrolling Interest [Line Items] | |||
Offer and issuance of stock (in Shares) | 43,700,000 | ||
Shares issued (in USD per share) | $ 17.50 | ||
Consideration received from offering | $ 720 | ||
Rattler MIdstream LP | Over-Allotment Option | |||
Noncontrolling Interest [Line Items] | |||
Offer and issuance of stock (in Shares) | 5,700,000 | ||
Rattler MIdstream LP | Rattler Partnership Agreement | |||
Noncontrolling Interest [Line Items] | |||
Amount allocated by general partners per Partnership Agreement | $ 0.1 | ||
Rattler MIdstream LP | Rattler's Services and Secondment Agreement | |||
Noncontrolling Interest [Line Items] | |||
Amount allocated by general partners per Partnership Agreement | 2 | ||
Rattler MIdstream LP | Rattler Tax Sharing Agreement | |||
Noncontrolling Interest [Line Items] | |||
Accrued state income tax expense | $ 0.1 | ||
Rattler MIdstream LP | Class B Units | |||
Noncontrolling Interest [Line Items] | |||
Limited partners' capital account, units issued (in Shares) | 107,815,152 | ||
Rattler LLC | |||
Noncontrolling Interest [Line Items] | |||
Distribution to affiliates | $ 727 |
REAL ESTATE ASSETS (Details)
REAL ESTATE ASSETS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2020 | Dec. 31, 2019 | |
Real Estate [Line Items] | ||
Buildings | $ 102 | $ 102 |
Tenant improvements | 5 | 5 |
Land | 2 | 2 |
Land improvements | 1 | 1 |
Total real estate assets | 110 | 110 |
Less: accumulated depreciation | (10) | (9) |
Total investment in land and buildings, net | 100 | 101 |
Finite-lived intangible assets, net | $ 7 | 8 |
In-place lease intangibles | ||
Real Estate [Line Items] | ||
Lease intangible assets, useful life | 45 months | |
Finite-lived intangible assets, gross | $ 11 | 11 |
Less: accumulated amortization | (6) | (6) |
Finite-lived intangible assets, net | $ 5 | 5 |
Above-market lease intangibles | ||
Real Estate [Line Items] | ||
Lease intangible assets, useful life | 45 months | |
Finite-lived intangible assets, gross | $ 3 | 4 |
Less: accumulated amortization | (1) | (1) |
Finite-lived intangible assets, net | $ 2 | $ 3 |
Buildings | Minimum | ||
Real Estate [Line Items] | ||
Real estate assets, estimated useful lives | 20 years | |
Buildings | Maximum | ||
Real Estate [Line Items] | ||
Real estate assets, estimated useful lives | 30 years | |
Tenant improvements | ||
Real Estate [Line Items] | ||
Real estate assets, estimated useful lives | 15 years | |
Land improvements | ||
Real Estate [Line Items] | ||
Real estate assets, estimated useful lives | 15 years |
PROPERTY AND EQUIPMENT (Details
PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2020 | Mar. 31, 2019 | Mar. 31, 2018 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2019 | |
Oil and natural gas properties: | ||||||
Not subject to depletion | $ 8,488 | $ 9,207 | ||||
Gross oil and natural gas properties | 26,719 | 25,782 | ||||
Accumulated depletion and depreciation | (6,416) | (5,003) | ||||
Midstream assets | 987 | 931 | ||||
Other property, equipment and land | 130 | 125 | ||||
Net property and equipment | 21,420 | 21,835 | ||||
Capitalized internal costs | $ 14 | $ 13 | ||||
Estimated future net revenue discounted rate per annum | 10.00% | |||||
Impairment of oil and natural gas properties | $ 1,009 | 0 | ||||
Exploration costs or development costs not subject to depletion | 228 | 228 | ||||
Capitalized interest not subject to depletion | $ 111 | 118 | ||||
Maximum | ||||||
Oil and natural gas properties: | ||||||
Timing of inclusion of costs in amortization calculation | 5 years | |||||
Oil and Natural Gas | ||||||
Oil and natural gas properties: | ||||||
Subject to depletion | $ 18,231 | 16,575 | ||||
Not subject to depletion | 8,488 | 9,207 | ||||
Gross oil and natural gas properties | 26,719 | 25,782 | ||||
Accumulated depletion and depreciation | (3,387) | (2,995) | ||||
Accumulated impairment | (2,943) | (1,934) | ||||
Oil and natural gas properties, net | 20,389 | 20,853 | ||||
Balance of costs not subject to depletion: | 59 | $ 604 | $ 5,398 | $ 303 | $ 2,124 | |
Other Property and Equipment, Net | ||||||
Oil and natural gas properties: | ||||||
Accumulated depletion and depreciation | (86) | (74) | ||||
Other property, equipment and land | $ 130 | $ 125 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2020 | Mar. 31, 2019 | Dec. 31, 2019 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligations, beginning of period | $ 94 | $ 136 | |
Additional liabilities incurred | 4 | 1 | |
Liabilities acquired | 0 | 3 | |
Liabilities settled | 0 | (2) | |
Accretion expense | 2 | 2 | |
Revisions in estimated liabilities | 0 | 0 | |
Asset retirement obligations, end of period | 100 | 140 | |
Less current portion | 1 | 0 | |
Asset retirement obligations - long-term | $ 99 | $ 140 | $ 94 |
Equity Method Investments (Deta
Equity Method Investments (Details) | 3 Months Ended | |||||||||
Mar. 31, 2020USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2019USD ($) | Dec. 20, 2019Mcf / dmi | Nov. 07, 2019 | Oct. 01, 2019 | Jul. 30, 2019 | Mar. 29, 2019USD ($) | Feb. 15, 2019 | Feb. 01, 2019 | |
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method investments | $ 502,000,000 | $ 479,000,000 | ||||||||
Impairments in equity method investments | 0 | $ 0 | ||||||||
Capitalized interest related equity method investment | 300,000 | $ 0 | ||||||||
Rattler LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method investments | 502,000,000 | 479,000,000 | ||||||||
Rattler LLC | Joint Venture of Wink to Webster Project | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Ownership percentage | 4.00% | |||||||||
OMOG JV LLC | Reliance Gathering LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Percentage of voting interests acquired | 100.00% | |||||||||
Amarillo Rattler, LLC | Dawson, Martin and Andrews Counties, Texas | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Gas gathering and cryogenic processing system capacity | Mcf / d | 40,000 | |||||||||
Distance of gathering and regional transportation pipelines | mi | 84 | |||||||||
EPIC Crude Holdings, LP | Rattler LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method interest investment ownership percentage | 10.00% | |||||||||
Equity method investments | 117,000,000 | 109,000,000 | ||||||||
Gray Oak Pipeline | Rattler LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method interest investment ownership percentage | 10.00% | |||||||||
Equity method investments | 122,000,000 | 116,000,000 | ||||||||
Gray Oak Pipeline | Rattler LLC | 2.52% Short-Term Promissory Note | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method investment promissory note | $ 123,000,000 | |||||||||
Debt instrument stated interest rate | 2.52% | |||||||||
Repayment of the Note | 0 | |||||||||
Loans outstanding | 0 | |||||||||
Wink to Webster Pipeline LLC | Rattler LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method interest investment ownership percentage | 4.00% | |||||||||
Equity method investments | 45,000,000 | 34,000,000 | ||||||||
OMOG JV LLC | Rattler LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method interest investment ownership percentage | 60.00% | |||||||||
Equity method investments | 216,000,000 | 219,000,000 | ||||||||
Amarillo Rattler, LLC | Martin County, Texas | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Gas gathering and cryogenic processing system capacity | Mcf / d | 60,000 | |||||||||
Amarillo Rattler, LLC | Rattler LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity method interest investment ownership percentage | 50.00% | |||||||||
Equity method investments | $ 2,000,000 | $ 1,000,000 |
DEBT - Long-term Debt (Details)
DEBT - Long-term Debt (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 | Dec. 05, 2019 |
Debt Instrument [Line Items] | |||
Unamortized debt issuance costs | $ (19) | $ (19) | |
Unamortized discount costs | (31) | (31) | |
Unamortized premium costs | 18 | 9 | |
Total long-term debt | 5,677 | 5,371 | |
4.625% Notes due 2021 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 400 | 399 | |
Debt instrument stated interest rate | 4.625% | ||
7.320% Medium-term Notes, Series A, due 2022 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 20 | 21 | |
Debt instrument stated interest rate | 7.32% | ||
2.875% Senior Notes due 2024 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 1,000 | 1,000 | |
Debt instrument stated interest rate | 2.875% | 2.875% | |
5.375% Senior Notes due 2025 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 800 | 800 | |
Debt instrument stated interest rate | 5.375% | ||
3.250% Senior Notes due 2026 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 800 | 800 | |
Debt instrument stated interest rate | 3.25% | 3.25% | |
7.350% Medium-term Notes, Series A, due 2027 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 10 | 11 | |
Debt instrument stated interest rate | 7.35% | ||
7.125% Medium-term Notes, Series B, due 2028 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 100 | 108 | |
Debt instrument stated interest rate | 7.125% | ||
3.500% Senior Notes due 2029 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 1,200 | 1,200 | |
Debt instrument stated interest rate | 3.50% | 3.50% | |
DrillCo Agreement | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 55 | 39 | |
Company revolving credit facility | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | 199 | 13 | |
Viper revolving credit facility | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | 174 | 97 | |
Viper 5.375% Senior Notes due 2027 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 500 | 500 | |
Debt instrument stated interest rate | 5.375% | ||
Rattler revolving credit facility | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings on revolving credit facility | $ 451 | $ 424 |
DEBT - Diamondback Notes (Detai
DEBT - Diamondback Notes (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2020 | Dec. 31, 2019 | Dec. 05, 2019 | Jan. 29, 2018 | Dec. 20, 2016 | |
Existing 2025 Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount | $ 500,000,000 | ||||
Debt instrument stated interest rate | 5.375% | ||||
New 2025 Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount | $ 300,000,000 | ||||
Debt instrument stated interest rate | 5.375% | ||||
5.375% Senior Notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Debt instrument stated interest rate | 5.375% | ||||
Debt, redemption price, percentage | 100.00% | ||||
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period One | |||||
Debt Instrument [Line Items] | |||||
Debt, redemption price, percentage | 104.031% | ||||
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Two | |||||
Debt Instrument [Line Items] | |||||
Debt, redemption price, percentage | 102.688% | ||||
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Three | |||||
Debt Instrument [Line Items] | |||||
Debt, redemption price, percentage | 101.344% | ||||
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Four | |||||
Debt Instrument [Line Items] | |||||
Debt, redemption price, percentage | 100.00% | ||||
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Five | |||||
Debt Instrument [Line Items] | |||||
Debt, redemption price, percentage | 105.375% | ||||
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Five | Maximum | |||||
Debt Instrument [Line Items] | |||||
Debt instrument percentage eligible for redemption | 35.00% | ||||
2.875% Senior Notes due 2024 | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount | $ 1,000,000,000 | ||||
Debt instrument stated interest rate | 2.875% | 2.875% | |||
3.250% Senior Notes due 2026 | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount | $ 800,000,000 | ||||
Debt instrument stated interest rate | 3.25% | 3.25% | |||
3.500% Senior Notes due 2029 | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount | $ 1,200,000,000 | ||||
Debt instrument stated interest rate | 3.50% | 3.50% | |||
Senior Notes | December 2019 Notes | |||||
Debt Instrument [Line Items] | |||||
Debt, redemption price, percentage | 100.00% | ||||
Debt, redemption price, percentage upon change of control triggering event | 101.00% |
DEBT - Second Amended and Resta
DEBT - Second Amended and Restated Credit Facility (Details) - Revolving credit facility - USD ($) | 3 Months Ended | |
Mar. 31, 2020 | Dec. 31, 2019 | |
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 2,000,000,000 | |
Outstanding borrowings | 199,000,000 | $ 13,000,000 |
Remaining borrowing capacity | $ 1,800,000,000 | |
Maximum | ||
Line of Credit Facility [Line Items] | ||
Debt covenant, total net debt to capitalization ratio | 65.00% | |
Debt covenant, debt principal amount as percentage of net tangible assets | 15.00% | |
Federal Funds Rate | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.50% | |
LIBOR | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.00% | |
Investment Grade Annually | Minimum | ||
Line of Credit Facility [Line Items] | ||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.125% | |
Investment Grade Annually | Maximum | ||
Line of Credit Facility [Line Items] | ||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.35% | |
Investment Grade Annually | Base Rate | Minimum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.125% | |
Investment Grade Annually | Base Rate | Maximum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.00% | |
Investment Grade Annually | LIBOR | Minimum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.125% | |
Investment Grade Annually | LIBOR | Maximum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 2.00% |
DEBT - Energen Notes (Details)
DEBT - Energen Notes (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 | Nov. 29, 2018 |
Energen Notes | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings | $ 530 | ||
4.625% Notes due 2021 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings | $ 400 | $ 399 | |
Debt instrument stated interest rate | 4.625% | ||
7.125% Medium-term Notes, Series B, due 2028 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings | $ 100 | 108 | |
Debt instrument stated interest rate | 7.125% | ||
7.320% Medium-term Notes, Series A, due 2022 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings | $ 20 | 21 | |
Debt instrument stated interest rate | 7.32% | ||
7.350% Medium-term Notes, Series A, due 2027 | |||
Debt Instrument [Line Items] | |||
Outstanding borrowings | $ 10 | $ 11 | |
Debt instrument stated interest rate | 7.35% |
DEBT - Viper_s Credit Agreement
DEBT - Viper’s Credit Agreement (Details) - Viper revolving credit facility | Jul. 20, 2018USD ($)redetermindation | Mar. 31, 2020USD ($) | May 15, 2020USD ($) | Dec. 31, 2019USD ($) |
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $ 2,000,000,000 | |||
Current borrowing capacity | $ 775,000,000 | |||
Number of redeterminations | redetermindation | 3 | |||
Period of redetermination | 12 months | |||
Outstanding borrowings | 174,000,000 | $ 97,000,000 | ||
Remaining borrowing capacity | 601,000,000 | |||
Maximum issuance of additional indebtedness | $ 1,000,000,000 | |||
Decrease of borrowing base | 25.00% | |||
Forecast | ||||
Line of Credit Facility [Line Items] | ||||
Decrease In current borrowing capacity | $ 580,000,000 | |||
Remaining borrowing capacity pending redetermination | $ 407,000,000 | |||
Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.375% | |||
Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.50% | |||
Federal Funds Rate | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.50% | |||
LIBOR | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.00% | |||
LIBOR | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.75% | |||
LIBOR | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 2.75% | |||
Base Rate | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.75% | |||
Base Rate | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.75% |
DEBT - Viper_s Notes (Details)
DEBT - Viper’s Notes (Details) - Viper 5.375% Senior Notes due 2027 - USD ($) | Oct. 16, 2019 | Mar. 31, 2020 |
Debt Instrument [Line Items] | ||
Debt instrument stated interest rate | 5.375% | |
Viper Energy Partners LP | Senior Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument stated interest rate | 5.375% | |
Aggregate principal amount | $ 500,000,000 | |
Proceeds from issuance of senior debt | $ 500,000,000 |
DEBT - Rattler's Credit Agreeme
DEBT - Rattler's Credit Agreement (Details) - Rattler revolving credit facility - USD ($) | 3 Months Ended | |
Mar. 31, 2020 | Dec. 31, 2019 | |
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 600,000,000 | |
Outstanding borrowings | 451,000,000 | $ 424,000,000 |
Remaining borrowing capacity | $ 149,000,000 | |
Minimum | ||
Line of Credit Facility [Line Items] | ||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.25% | |
Maximum | ||
Line of Credit Facility [Line Items] | ||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.375% | |
Prime Rate | Minimum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.25% | |
Prime Rate | Maximum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.25% | |
LIBOR | Minimum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.25% | |
LIBOR | Maximum | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 2.25% |
DEBT - Financial Covenant Table
DEBT - Financial Covenant Table (Details) | 3 Months Ended |
Mar. 31, 2020 | |
Viper revolving credit facility | Maximum | |
Line of Credit Facility [Line Items] | |
Ratio of total net debt to EBITDAX, as defined in the credit agreement | 4 |
Viper revolving credit facility | Minimum | |
Line of Credit Facility [Line Items] | |
Ratio of current assets to liabilities, as defined in the credit agreement | 1 |
Rattler revolving credit facility | Maximum | |
Line of Credit Facility [Line Items] | |
Line of credit, covenant terms, consolidated total leverage ratio | 5 |
Line of credit, covenant terms, consolidated total leverage ratio, for three fiscal quarters following certain acquisitions | 5.50 |
Line of credit, covenant terms, consolidated total leverage ratio when consolidated senior secured leverage ration is applicable | 5.25 |
Line of credit facility, covenant terms, ratio of consolidated senior secured leverage ratio | 3.5 |
Rattler revolving credit facility | Minimum | |
Line of Credit Facility [Line Items] | |
Line of credit facility, covenant terms ratio of consolidated interest coverage | 2.5 |
DEBT - Alliance with Obsidian R
DEBT - Alliance with Obsidian Resources, L.L.C. (Details) - DrillCo Agreement $ in Millions | 3 Months Ended | ||
Mar. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Sep. 10, 2018USD ($) | |
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items] | |||
Maximum funding amount through joint venture | $ 300 | ||
Percentage of funded costs associated with wells drilled | 85.00% | ||
Percentage of working interest on wells expected to receive | 80.00% | ||
Cumulative percentage of certain payout thresholds | 9.00% | ||
Internal rate of return | 13.00% | ||
Interest rate upon reaching final internal rate of return | 85.00% | ||
Amounts received from joint venture | $ 55 | $ 39 | |
Wells drilled and completed under joint venture agreement | 13 | ||
CEMOF | |||
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items] | |||
Interest rate upon reaching final internal rate of return | 15.00% |
CAPITAL STOCK AND EARNINGS PE_3
CAPITAL STOCK AND EARNINGS PER SHARE - Capital Stock (Details) - USD ($) | 3 Months Ended | |
Mar. 31, 2020 | May 31, 2019 | |
Equity [Abstract] | ||
Stock repurchase program authorized amount | $ 2,000,000,000 | |
Stock repurchase program amount repurchased | $ 98,000,000 | |
Stock repurchase remaining authorized amount | $ 1,300,000,000 |
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, 2020 | Mar. 31, 2019 | |
Basic: | ||
Net (loss) income attributable to common stock | $ (272) | $ 10 |
Basic weighted average common units outstanding (in shares) | 158,291 | 164,852 |
Effect of dilutive securities: | ||
Dilutive effect of potential common shares issuable (in shares) | 203 | 209 |
Diluted: | ||
Diluted weighted average common shares outstanding (in shares) | 158,494 | 165,061 |
Basic net income attributable to common stock (in USD per share) | $ (1.72) | $ 0.06 |
Diluted net income attributable to common stock (in USD per share) | $ (1.72) | $ 0.06 |
Restricted stock units (in shares) | 318 | 31 |
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, 2020 | Mar. 31, 2019 | |
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items] | ||
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties | $ 6 | $ 6 |
General and administrative expenses | ||
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items] | ||
General and administrative expenses | $ 9 | $ 14 |
EQUITY-BASED COMPENSATION - Res
EQUITY-BASED COMPENSATION - Restricted Stock Units (Details) - Equity Plan - Restricted Stock Units (RSUs) | 3 Months Ended |
Mar. 31, 2020$ / sharesshares | |
Restricted Stock Awards & Units (in Shares) | |
Unvested, beginning balance (in shares) | shares | 505,867 |
Granted (in shares) | shares | 159,116 |
Vested (in shares) | shares | (104,640) |
Forfeited (in shares) | shares | (13,610) |
Unvested, ending balance (in shares) | shares | 546,733 |
Weighted Average Grant-Date Fair Value | |
Unvested, beginning balance (in USD per share) | $ / shares | $ 96.01 |
Granted (in USD per share) | $ / shares | 62.82 |
Vested (in USD per share) | $ / shares | 80.75 |
Forfeited (in USD per share) | $ / shares | 99.72 |
Unvested, ending balance (in USD per share) | $ / shares | $ 89.18 |
EQUITY-BASED COMPENSATION - R_2
EQUITY-BASED COMPENSATION - Restricted Stock Units (Narratives) (Details) - Restricted Stock Units (RSUs) - Equity Plan | 3 Months Ended | |
Mar. 31, 2020USD ($)award | Mar. 31, 2019USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Aggregated fair value of restricted stock | $ 8,000,000 | $ 13,000,000 |
Share based award not recognized | $ 38,000,000 | |
Share based payment not recognized | 2 years 1 month 6 days | |
Number of awards impacted | award | 765 | |
Incremental compensation | $ 0 |
EQUITY-BASED COMPENSATION - Per
EQUITY-BASED COMPENSATION - Performance Based Restricted Stock Units (Narratives) (Details) - Performance Shares - Equity Plan - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended |
Mar. 31, 2019 | Mar. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Granted (in shares) | 272,601 | |
Share based compensation arrangement by share based payment maximum award potential | 976,940 | |
Share based award not recognized | $ 35 | |
Share based payment not recognized | 2 years 6 months | |
Share-based Payment Arrangement, Tranche One | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Performance shares, performance period | 3 years | |
Granted (in shares) | 225,047 | |
Share-based Payment Arrangement, Tranche One | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted | 0.00% | |
Share-based Payment Arrangement, Tranche One | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted | 200.00% |
EQUITY-BASED COMPENSATION - Val
EQUITY-BASED COMPENSATION - Valuation Assumptions (Details) - Equity Plan - Performance Shares | 3 Months Ended |
Mar. 31, 2020$ / shares | |
Restricted Stock Awards & Units | |
Granted (in USD per share) | $ 85.73 |
Five-Year | |
Restricted Stock Awards & Units | |
Granted (in USD per share) | $ 70.17 |
Risk-free rate | 0.86% |
Company volatility | 36.70% |
EQUITY-BASED COMPENSATION - P_2
EQUITY-BASED COMPENSATION - Performance Restricted Stock Activity (Details) - Equity Plan - Performance Shares - $ / shares | 1 Months Ended | 3 Months Ended |
Mar. 31, 2019 | Mar. 31, 2020 | |
Awards & Units (in shares) | ||
Unvested, beginning balance (in shares) | 271,819 | |
Granted (in shares) | 272,601 | |
Vested (in shares) | (47,554) | |
Forfeited (in shares) | (8,396) | |
Unvested, ending balance (in shares) | 488,470 | |
Weighted Average Exercise Price (in USD per share) | ||
Unvested, beginning balance (in USD per share) | $ 147.07 | |
Granted (in USD per share) | 85.73 | |
Vested (in USD per share) | 89.27 | |
Forfeited (in USD per share) | 170.45 | |
Unvested, ending balance (in USD per share) | $ 110.33 | |
Share based compensation arrangement by share based payment maximum award potential | 976,940 | |
Three-Year | ||
Awards & Units (in shares) | ||
Granted (in shares) | 225,047 | |
Five-Year | ||
Weighted Average Exercise Price (in USD per share) | ||
Granted (in USD per share) | $ 70.17 |
EQUITY-BASED COMPENSATION - Sto
EQUITY-BASED COMPENSATION - Stock Appreciation Rights (Details) | 3 Months Ended |
Mar. 31, 2020$ / sharesshares | |
Restricted Stock Awards & Units (in Shares) | |
Outstanding at December 31, 2019 | shares | 216,343 |
Exercised | shares | (11,338) |
Outstanding at March 31, 2020 | shares | 205,005 |
Weighted Average Exercise Price (in USD per share) | |
Outstanding at December 31, 2019 | $ / shares | $ 89.90 |
Exercised | $ / shares | 72.48 |
Outstanding at March 31, 2020 | $ / shares | $ 91.58 |
Equity Plan | Stock Appreciation Rights (SARs) | |
Restricted Stock Awards & Units | |
Award requisite service period | 3 years |
Restricted Stock Awards & Units (in Shares) | |
Outstanding at December 31, 2019 | shares | 42,547 |
Exercised | shares | (4,213) |
Expired | shares | (970) |
Outstanding at March 31, 2020 | shares | 37,364 |
Weighted Average Exercise Price (in USD per share) | |
Outstanding at December 31, 2019 | $ / shares | $ 90.89 |
Exercised | $ / shares | 72.67 |
Expired | $ / shares | 72.48 |
Outstanding at March 31, 2020 | $ / shares | $ 93.42 |
EQUITY-BASED COMPENSATION - S_2
EQUITY-BASED COMPENSATION - Stock Options (Details) $ / shares in Units, $ in Millions | 3 Months Ended |
Mar. 31, 2020USD ($)$ / sharesshares | |
Options (in shares) | |
Outstanding at December 31, 2019 | shares | 216,343 |
Exercised | shares | (11,338) |
Outstanding at March 31, 2020 | shares | 205,005 |
Weighted Average Exercise Price (in USD per share) | |
Outstanding at December 31, 2019 | $ / shares | $ 89.90 |
Exercised | $ / shares | 72.48 |
Outstanding at March 31, 2020 | $ / shares | $ 91.58 |
Weighted average remaining contractual term | 1 year 6 months 3 days |
Intrinsic value of options outstanding | $ | $ 0 |
Vested and Expected to vest at September 30, 2019 (in Shares) | shares | 205,005 |
Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price (in Shares) | $ / shares | $ 91.58 |
Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term | 1 year 6 months 3 days |
Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value | $ | $ 0 |
Options, Vested and Expected to Vest, Exercisable, Number (in Shares) | shares | 205,005 |
Options, Vested and Expected to Vest, Exercisable, Weighted Average Exercise Price (in Shares) | $ / shares | $ 91.58 |
Options, Vested and Expected to Vest, Exercisable, Weighted Average Remaining Contractual Term | 1 year 6 months 3 days |
Options, Vested and Expected to Vest, Exercisable, Aggregate Intrinsic Value | $ | $ 0 |
EQUITY-BASED COMPENSATION - Vip
EQUITY-BASED COMPENSATION - Viper Phantom Units (Details) - Viper Energy Partners LP Long Term Incentive Plan - Phantom Share Units (PSUs) | 3 Months Ended |
Mar. 31, 2020$ / sharesshares | |
Phantom Units | |
Unvested, beginning balance (in shares) | shares | 95,248 |
Vested (in shares) | shares | (42,814) |
Unvested, ending balance (in shares) | shares | 52,434 |
Weighted Average Grant-Date Fair Value | |
Unvested, beginning balance (in USD per share) | $ / shares | $ 26.87 |
Vested (in USD per share) | $ / shares | 23.24 |
Unvested, ending balance (in USD per share) | $ / shares | $ 29.83 |
EQUITY-BASED COMPENSATION - V_2
EQUITY-BASED COMPENSATION - Viper Phantom Units (Narratives) (Details) - Phantom Share Units (PSUs) - Viper Energy Partners LP Long Term Incentive Plan $ in Millions | 3 Months Ended |
Mar. 31, 2020USD ($)award | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Aggregated fair value of restricted stock | $ 1 |
Share based award not recognized | $ 1 |
Share based payment not recognized | 1 year 4 months 24 days |
Number of awards impacted | award | 21 |
EQUITY-BASED COMPENSATION - Rat
EQUITY-BASED COMPENSATION - Rattler Phantom Units (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan | 3 Months Ended |
Mar. 31, 2020$ / sharesshares | |
Phantom Units | |
Unvested, beginning balance (in shares) | shares | 2,226,895 |
Granted (in shares) | shares | 20,910 |
Forfeited (in shares) | shares | (569) |
Unvested, ending balance (in shares) | shares | 2,247,236 |
Weighted Average Grant-Date Fair Value | |
Unvested, beginning balance (in USD per share) | $ / shares | $ 19.14 |
Granted (in USD per share) | $ / shares | 13.85 |
Forfeited (in USD per share) | $ / shares | 15.57 |
Unvested, ending balance (in USD per share) | $ / shares | $ 19.09 |
EQUITY-BASED COMPENSATION - R_3
EQUITY-BASED COMPENSATION - Rattler Phantom Units (Narratives) (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan [Member] $ in Millions | 3 Months Ended |
Mar. 31, 2020USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share based award not recognized | $ 36 |
Share based payment not recognized | 4 years 1 month 6 days |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - Viper Energy Partners LP - Subsidiaries $ in Millions | 3 Months Ended |
Mar. 31, 2020USD ($)lease | |
Related Party Transaction [Line Items] | |
Related party transaction amounts | $ 0.3 |
Number of leases extended | 1 |
Revenue from related parties on new leases | $ 1.3 |
Number of new leases | lease | 1 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Investments, Owned, Federal Income Tax Note [Line Items] | ||
Effective income tax rate | (26.10%) | (301.70%) |
Discrete income tax benefit related to deferred taxes recorded during the period | $ 143 | $ 35 |
Discrete income tax benefit | (25) | |
Federal net losses | 179 | |
Current federal taxes receivable | $ 101 |
DERIVATIVES - Open Derivative P
DERIVATIVES - Open Derivative Positions (Details) Mcf in Thousands | 3 Months Ended |
Mar. 31, 2020MMBTU$ / bbl$ / MMBTU$ / McfbblMcf | |
WTI Cushing Oil Swaps 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 3,114,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 46.33 |
WTI Cushing Oil Swaps 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 0 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 0 |
WTI Magellan East Houston Oil Swaps 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 1,100,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 61.95 |
WTI Magellan East Houston Oil Swaps 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 1,825,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 37.78 |
BRENT Oil Swaps 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 7,292,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 48.80 |
BRENT Oil Swaps 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 3,816,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 43.26 |
BRENT Oil Swaption 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 0 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 0 |
BRENT Oil Swaption 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 2,024,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 44.77 |
Oil Basis Swaps - WTI Cushing 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 11,125,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | (1.21) |
WTI Cushing Oil Basis Swaps 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 0 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 0 |
Oil Rolling Hedge 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 5,500,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 0.44 |
Oil Rolling Hedge 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 0 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 0 |
Natural Gas Swaps 2020 - Henry Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 8,190,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 2.55 |
Natural Gas Swaps 2021 - Henry Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 14,600,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 2.47 |
Natural Gas Swaps Waha Hub 2020 | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 16,500,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 1.51 |
Natural Gas Swaps Waha Hub 2021 | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 0 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 0 |
Natural Gas Basis Swaps - Waha Hub 2020 | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 33,000,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | (1.46) |
Natural Gas Basis Swaps - Waha Hub 2021 | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 62,050,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | (0.71) |
Diesel Price Swaps 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 275,000,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 1.60 |
Diesel Price Swaps 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 0 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 0 |
Oil Swaption - WTI Magellan East Houston | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 2,750,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 55 |
Put price (per Bbl) | 40 |
WTI Cushing Oil Swaps 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 1,292,500 |
WTI Cushing Oil Swaps 2020 | Long | |
Derivative [Line Items] | |
Put price (per Bbl) | 46.51 |
Oil Put Spread - WTI Magellan East Houston 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 1,045,000 |
Floor price (per Bbl) | 50 |
Oil Put Spread - WTI Magellan East Houston 2020 | Short | |
Derivative [Line Items] | |
Put price (per Bbl) | 25 |
2020 Three-Way Collars - WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 10,182,975 |
Floor price (per Bbl) | 38.10 |
Ceiling price (per Bbl) | 45.02 |
2020 Three-Way Collars - BRENT | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 17,750,750 |
Floor price (per Bbl) | 37.64 |
Ceiling price (per Bbl) | 46.66 |
2020 Three-Way Collars - WTI Magellan East Houston | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 1,092,000 |
Floor price (per Bbl) | 39 |
Ceiling price (per Bbl) | 49 |
2021 Three-Way Collars - BRENT | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 21,717,500 |
Floor price (per Bbl) | 39.45 |
Ceiling price (per Bbl) | 48.16 |
Oil Swaps - WTI Cushing | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 275,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | 27.45 |
Oil Basis Swaps - WTI (Midland-Cushing) | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 1,100,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | (2.60) |
Natural Gas Swaps Waha Hub 2020 | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 6,875,000 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | (2.07) |
Gas Swap Double-Up - Waha Hub | |
Derivative [Line Items] | |
Volume (Bbls) | Mcf | 8,250 |
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / Mcf | 1.70 |
Option price (per Mcf) | $ / Mcf | 1.70 |
Collars - WTI (Cushing) 2020 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 3,850,000 |
Floor price (per Bbl) | 28.86 |
Ceiling price (per Bbl) | 32.33 |
Collars - WTI (Cushing) 2021 | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 3,650,000 |
Floor price (per Bbl) | 30 |
Ceiling price (per Bbl) | 43.05 |
DERIVATIVES - Interest rate swa
DERIVATIVES - Interest rate swaps and treasury locks (Details) $ in Millions | Mar. 31, 2020USD ($) |
Interest Rate Swap One | |
Offsetting Assets [Line Items] | |
Notional Amount (in millions) | $ 250 |
Interest Rate | 1.551% |
Interest Rate Swap Two | |
Offsetting Assets [Line Items] | |
Notional Amount (in millions) | $ 250 |
Interest Rate | 1.5575% |
Interest Rate Swap Three | |
Offsetting Assets [Line Items] | |
Notional Amount (in millions) | $ 250 |
Interest Rate | 1.297% |
Interest Rate Swap Four | |
Offsetting Assets [Line Items] | |
Notional Amount (in millions) | $ 250 |
Interest Rate | 1.195% |
DERIVATIVES - Offsetting Deriva
DERIVATIVES - Offsetting Derivative Instruments (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross amounts of assets presented in the Consolidated Balance Sheet | $ 818 | $ 71 |
Amounts netted in the Consolidated Balance Sheet | (254) | (18) |
Net amounts of assets presented in the Consolidated Balance Sheet | 564 | 53 |
Gross amounts of liabilities presented in the Consolidated Balance Sheet | 336 | 45 |
Amounts netted in the Consolidated Balance Sheet | (254) | (18) |
Net amounts of liabilities presented in the Consolidated Balance Sheet | $ 82 | $ 27 |
DERIVATIVES - Balance Sheet Loc
DERIVATIVES - Balance Sheet Location (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Current assets: derivative instruments | $ 534 | $ 46 |
Noncurrent assets: derivative instruments | 30 | 7 |
Net amounts of assets presented in the Consolidated Balance Sheet | 564 | 53 |
Current liabilities: derivative instruments | 16 | 27 |
Noncurrent liabilities: derivative instruments | 66 | 0 |
Net amounts of liabilities presented in the Consolidated Balance Sheet | $ 82 | $ 27 |
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, 2020 | Mar. 31, 2019 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Change in fair value of open non-hedge derivative instruments | $ 455 | $ (285) |
Gain on settlement of non-hedge derivative instruments | 87 | 17 |
Gain (loss) on derivative instruments, net | 542 | (268) |
Commodity contracts | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Change in fair value of open non-hedge derivative instruments | 517 | (285) |
Gain on settlement of non-hedge derivative instruments | 87 | 17 |
Interest rate swaps | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Change in fair value of open non-hedge derivative instruments | $ (62) | $ 0 |
FAIR VALUE MEASUREMENTS - Recur
FAIR VALUE MEASUREMENTS - Recurring Measurements (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 |
Assets: | ||
Derivative Instruments | $ 564 | $ 53 |
Liabilities: | ||
Derivative Instruments | 82 | 27 |
Viper Energy Partners LP | Recurring | Level 1 | ||
Assets: | ||
Investment | 9 | 19 |
Derivative Instruments | 0 | 0 |
Liabilities: | ||
Derivative Instruments | 0 | 0 |
Viper Energy Partners LP | Recurring | Level 2 | ||
Assets: | ||
Investment | 0 | 0 |
Derivative Instruments | 564 | 53 |
Liabilities: | ||
Derivative Instruments | 82 | 27 |
Viper Energy Partners LP | Recurring | Level 3 | ||
Assets: | ||
Investment | 0 | 0 |
Derivative Instruments | 0 | 0 |
Liabilities: | ||
Derivative Instruments | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - Nonre
FAIR VALUE MEASUREMENTS - Nonrecurring Measurements (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 | Dec. 05, 2019 |
4.625% Notes due 2021 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 4.625% | ||
7.320% Medium-term Notes, Series A, due 2022 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 7.32% | ||
2.875% Senior Notes due 2024 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 2.875% | 2.875% | |
5.375% Senior Notes due 2025 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 5.375% | ||
3.250% Senior Notes due 2026 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 3.25% | 3.25% | |
7.350% Medium-term Notes, Series A, due 2027 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 7.35% | ||
7.125% Medium-term Notes, Series B, due 2028 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 7.125% | ||
3.500% Senior Notes due 2029 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 3.50% | 3.50% | |
Viper 5.375% Senior Notes due 2027 | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt instrument stated interest rate | 5.375% | ||
Reported Value Measurement | Company revolving credit facility | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | $ 199 | $ 13 | |
Reported Value Measurement | 4.625% Notes due 2021 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 399 | 399 | |
Reported Value Measurement | 7.320% Medium-term Notes, Series A, due 2022 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 21 | 21 | |
Reported Value Measurement | 2.875% Senior Notes due 2024 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 992 | 992 | |
Reported Value Measurement | 5.375% Senior Notes due 2025 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 799 | 799 | |
Reported Value Measurement | 3.250% Senior Notes due 2026 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 792 | 792 | |
Reported Value Measurement | 7.350% Medium-term Notes, Series A, due 2027 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 11 | 11 | |
Reported Value Measurement | 7.125% Medium-term Notes, Series B, due 2028 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 107 | 108 | |
Reported Value Measurement | 3.500% Senior Notes due 2029 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 1,187 | 1,186 | |
Reported Value Measurement | Viper revolving credit facility | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | 174 | 97 | |
Reported Value Measurement | Viper 5.375% Senior Notes due 2027 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 490 | 490 | |
Reported Value Measurement | Rattler revolving credit facility | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | 451 | 424 | |
Reported Value Measurement | DrillCo Agreement | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt, fair value | 55 | 39 | |
Estimate of Fair Value Measurement | 4.625% Notes due 2021 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 369 | 411 | |
Estimate of Fair Value Measurement | 7.320% Medium-term Notes, Series A, due 2022 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 19 | 22 | |
Estimate of Fair Value Measurement | 7.350% Medium-term Notes, Series A, due 2027 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 9 | 12 | |
Estimate of Fair Value Measurement | 7.125% Medium-term Notes, Series B, due 2028 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 67 | 116 | |
Estimate of Fair Value Measurement | DrillCo Agreement | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Debt, fair value | 55 | 39 | |
Level 1 | Estimate of Fair Value Measurement | 2.875% Senior Notes due 2024 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 720 | 1,012 | |
Level 1 | Estimate of Fair Value Measurement | 5.375% Senior Notes due 2025 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 587 | 840 | |
Level 1 | Estimate of Fair Value Measurement | 3.250% Senior Notes due 2026 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 568 | 812 | |
Level 1 | Estimate of Fair Value Measurement | 3.500% Senior Notes due 2029 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 851 | 1,226 | |
Level 1 | Estimate of Fair Value Measurement | Viper 5.375% Senior Notes due 2027 | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Senior notes due | 420 | 521 | |
Level 2 | Estimate of Fair Value Measurement | Company revolving credit facility | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | 199 | 13 | |
Level 2 | Estimate of Fair Value Measurement | Viper revolving credit facility | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | 174 | 97 | |
Level 2 | Estimate of Fair Value Measurement | Rattler revolving credit facility | Nonrecurring | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | $ 451 | $ 424 |
LEASES - Additional Information
LEASES - Additional Information (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2020 | Mar. 31, 2019 | Jan. 01, 2019 | |
Lessee, Lease, Description [Line Items] | |||
Operating right of use asset | $ 18 | ||
Statement of consolidated cash flow | 5 | $ 5 | |
Additional amount of operating lease right of use asset recorded | 8 | ||
Operating lease liabilities | 18 | ||
Operating lease liability current | $ 12 | ||
Weighted average remaining lease term | 1 year 9 months 18 days | ||
Weighted average discount rate | 9.30% | ||
Accounting Standards Update 2016-02 | |||
Lessee, Lease, Description [Line Items] | |||
Operating right of use asset | $ 13 | ||
New lease liabilities | $ 13 |
LEASES - Summary of Operating L
LEASES - Summary of Operating Lease Costs (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Leases [Abstract] | ||
Operating lease costs | $ 5 | $ 4 |
LEASES - Summary of Undiscounte
LEASES - Summary of Undiscounted Cash Flows Owed by the Company to Lessors Pursuant to Contractual Agreements (Details) $ in Millions | Mar. 31, 2020USD ($) |
Leases [Abstract] | |
2020 | $ 11 |
2021 | 6 |
2022 | 3 |
2023 | 0 |
2024 | 0 |
Thereafter | 0 |
Total lease payments | 20 |
Less: interest | 2 |
Present value of lease liabilities | $ 18 |
SUBSEQUENT EVENTS - Narratives
SUBSEQUENT EVENTS - Narratives (Details) - USD ($) $ / shares in Units, $ in Millions | May 01, 2020 | Mar. 31, 2020 | Mar. 31, 2019 | May 15, 2020 |
Subsequent Event [Line Items] | ||||
Dividends declared per share (in USD per share) | $ 0.3750 | $ 0.1875 | ||
Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Dividends declared per share (in USD per share) | $ 0.3750 | |||
Viper revolving credit facility | Forecast | ||||
Subsequent Event [Line Items] | ||||
Decrease In current borrowing capacity | $ 580 | |||
Remaining borrowing capacity pending redetermination | $ 407 |
SUBSEQUENT EVENTS - Schedule of
SUBSEQUENT EVENTS - Schedule of Derivative Contracts (Details) | 3 Months Ended | 10 Months Ended | 12 Months Ended |
Mar. 31, 2020MMBTU$ / MMBTU | Dec. 31, 2020MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl | |
Oil Rolling Hedge - WTI | Forecast | Subsequent Event | |||
Subsequent Event [Line Items] | |||
Volume (Bbls) | bbl | 27,500,000 | ||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / bbl | (1.35) | ||
Natural Gas Swaps 2020 - Henry Hub | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 2.55 | ||
Volume, energy measure (MMBtu) | MMBTU | 8,190,000 | ||
Natural Gas Swaps 2020 - Henry Hub | Forecast | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 2.40 | ||
Volume, energy measure (MMBtu) | MMBTU | 5,520,000 | ||
Oil Basis Swaps - WTI Midland 2020 | Forecast | Subsequent Event | |||
Subsequent Event [Line Items] | |||
Volume (Bbls) | bbl | 1,712,000 | ||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / bbl | (1.31) | ||
Natural Gas Swaps 2021 - Henry Hub | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 2.47 | ||
Volume, energy measure (MMBtu) | MMBTU | 14,600,000 | ||
Natural Gas Swaps 2021 - Henry Hub | Forecast | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 2.62 | ||
Volume, energy measure (MMBtu) | MMBTU | 29,200,000 | ||
Natural Gas Swaps Waha Hub 2021 | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 0 | ||
Volume, energy measure (MMBtu) | MMBTU | 0 | ||
Natural Gas Swaps Waha Hub 2021 | Forecast | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | 0.70 | ||
Volume, energy measure (MMBtu) | MMBTU | 1,095,000 | ||
Natural Gas Basis Swaps - Waha Hub 2021 | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | (0.71) | ||
Volume, energy measure (MMBtu) | MMBTU | 62,050,000 | ||
Natural Gas Basis Swaps - Waha Hub 2021 | Forecast | |||
Subsequent Event [Line Items] | |||
Fixed Price Swap (per Bbl/MMBtu/Gallon) | $ / MMBTU | (0.56) | ||
Volume, energy measure (MMBtu) | MMBTU | 10,950,000 | ||
Oil Costless Collar | Forecast | |||
Subsequent Event [Line Items] | |||
Volume (Bbls) | bbl | 730,000 | ||
Floor price (per Bbl) | $ / bbl | 25 | ||
Ceiling price (per Bbl) | $ / bbl | 38.40 |
REPORT OF BUSINESS SEGMENTS - A
REPORT OF BUSINESS SEGMENTS - Additional Information (Details) | 3 Months Ended |
Mar. 31, 2020segment | |
Segment Reporting [Abstract] | |
Number of business segments | 2 |
REPORT OF BUSINESS SEGMENTS - S
REPORT OF BUSINESS SEGMENTS - Summary of Business Segments (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2020 | Mar. 31, 2019 | Dec. 31, 2019 | |
Segment Reporting Information [Line Items] | |||
Total revenues | $ 899 | $ 864 | |
Depreciation, depletion and amortization | 407 | 322 | |
Impairment of oil and natural gas properties | 1,009 | 0 | |
(Loss) income from operations | (802) | 319 | |
Interest expense, net | (48) | (46) | |
Other income (expense) | 485 | (309) | |
Provision for income taxes | 83 | (33) | |
Net (loss) income attributable to non-controlling interest | (128) | 33 | |
Net (loss) income attributable to Diamondback Energy, Inc. | (272) | 10 | |
Total assets | 23,386 | 23,531 | $ 23,531 |
Upstream | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 883 | 843 | |
Midstream Services | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 129 | 95 | |
Operating Segments | Upstream | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 883 | 843 | |
Depreciation, depletion and amortization | 394 | 312 | |
Impairment of oil and natural gas properties | 1,009 | ||
(Loss) income from operations | (782) | 300 | |
Interest expense, net | (45) | (46) | |
Other income (expense) | 489 | (308) | |
Provision for income taxes | 79 | (44) | |
Net (loss) income attributable to non-controlling interest | (128) | 33 | |
Net (loss) income attributable to Diamondback Energy, Inc. | (244) | 3 | |
Total assets | 21,875 | 22,125 | |
Operating Segments | Midstream Services | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 16 | 21 | |
Depreciation, depletion and amortization | 13 | 10 | |
Impairment of oil and natural gas properties | 0 | ||
(Loss) income from operations | 61 | 50 | |
Interest expense, net | (3) | 0 | |
Other income (expense) | (3) | 0 | |
Provision for income taxes | 4 | 11 | |
Net (loss) income attributable to non-controlling interest | 41 | 0 | |
Net (loss) income attributable to Diamondback Energy, Inc. | 13 | 39 | |
Total assets | 1,676 | 1,636 | |
Eliminations | |||
Segment Reporting Information [Line Items] | |||
Total revenues | (113) | (74) | |
Depreciation, depletion and amortization | 0 | 0 | |
Impairment of oil and natural gas properties | 0 | ||
(Loss) income from operations | (81) | (31) | |
Interest expense, net | 0 | 0 | |
Other income (expense) | (1) | (1) | |
Provision for income taxes | 0 | 0 | |
Net (loss) income attributable to non-controlling interest | (41) | 0 | |
Net (loss) income attributable to Diamondback Energy, Inc. | (41) | (32) | |
Total assets | $ (165) | $ (230) |