Cover
Cover - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 18, 2022 | Jun. 30, 2021 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Current Fiscal Year End Date | --12-31 | ||
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, par value $0.01 per share | ||
Trading Symbol | FANG | ||
Security Exchange Name | NASDAQ | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
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 | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 16.9 | ||
Entity Common Stock, Shares Outstanding | 177,414,969 | ||
Documents Incorporated by Reference | Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2022 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K. | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY | ||
Entity Central Index Key | 0001539838 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2021 | |
Audit Information [Abstract] | |
Auditor Firm ID | 248 |
Auditor Name | GRANT THORNTON LLP |
Auditor Location | Oklahoma City, Oklahoma |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets: | ||
Cash and cash equivalents | $ 654 | $ 104 |
Restricted cash | 18 | 4 |
Accounts receivable: | ||
Joint interest and other, net | 72 | 56 |
Oil and natural gas sales, net | 598 | 281 |
Inventories | 62 | 33 |
Derivative instruments | 13 | 1 |
Income tax receivable | 1 | 100 |
Prepaid expenses and other current assets | 28 | 23 |
Total current assets | 1,446 | 602 |
Property and equipment: | ||
Oil and natural gas properties, full cost method of accounting ($8,496 million and $7,493 million excluded from amortization at December 31, 2021 and December 31, 2020, respectively) | 32,914 | 27,377 |
Midstream assets | 1,076 | 1,013 |
Other property, equipment and land | 174 | 138 |
Accumulated depletion, depreciation, amortization and impairment | (13,545) | (12,314) |
Property and equipment, net | 20,619 | 16,214 |
Funds held in escrow | 12 | 51 |
Equity method investments | 613 | 533 |
Derivative instruments | 4 | 0 |
Deferred income taxes, net | 40 | 73 |
Investment in real estate, net | 88 | 101 |
Other assets | 76 | 45 |
Total assets | 22,898 | 17,619 |
Current liabilities: | ||
Accounts payable - trade | 36 | 71 |
Accrued capital expenditures | 295 | 186 |
Current maturities of long-term debt | 45 | 191 |
Other accrued liabilities | 436 | 302 |
Revenues and royalties payable | 452 | 237 |
Derivative instruments | 174 | 249 |
Total current liabilities | 1,438 | 1,236 |
Long-term debt | 6,642 | 5,624 |
Derivative instruments | 29 | 57 |
Asset retirement obligations | 166 | 108 |
Deferred income taxes | 1,338 | 783 |
Other long-term liabilities | 40 | 7 |
Total liabilities | 9,653 | 7,815 |
Commitments and contingencies (Note 18) | ||
Stockholders’ equity: | ||
Common stock, $0.01 par value; 400,000,000 shares authorized; 177,551,347 and 158,088,182 shares issued and outstanding at December 31, 2021 and December 31, 2020, respectively | 2 | 2 |
Additional paid-in capital | 14,084 | 12,656 |
Retained earnings (accumulated deficit) | (1,998) | (3,864) |
Total Diamondback Energy, Inc. stockholders’ equity | 12,088 | 8,794 |
Non-controlling interest | 1,157 | 1,010 |
Total equity | 13,245 | 9,804 |
Total liabilities and equity | $ 22,898 | $ 17,619 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Statement of Financial Position [Abstract] | ||
Oil and natural gas properties, amortization excluded | $ 8,496 | $ 7,493 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in Shares) | 400,000,000 | 400,000,000 |
Common stock, shares issued (in Shares) | 177,551,347 | 158,088,182 |
Common stock, shares outstanding (in Shares) | 177,551,347 | 158,088,182 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Revenues: | |||
Revenues | $ 6,747,000,000 | $ 2,756,000,000 | $ 3,887,000,000 |
Other operating income | 5,000,000 | 7,000,000 | 13,000,000 |
Total revenues | 6,797,000,000 | 2,813,000,000 | 3,964,000,000 |
Costs and expenses: | |||
Lease operating expenses | 565,000,000 | 425,000,000 | 490,000,000 |
Production and ad valorem taxes | 425,000,000 | 195,000,000 | 248,000,000 |
Depreciation, depletion, amortization and accretion | 1,275,000,000 | 1,311,000,000 | 1,454,000,000 |
Impairment of oil and natural gas properties | 0 | 6,021,000,000 | 790,000,000 |
General and administrative expenses | 146,000,000 | 88,000,000 | 104,000,000 |
Merger and integration expense | 78,000,000 | 0 | 0 |
Other operating expense | 6,000,000 | 4,000,000 | 4,000,000 |
Total costs and expenses | 2,796,000,000 | 8,289,000,000 | 3,269,000,000 |
Income (loss) from operations | 4,001,000,000 | (5,476,000,000) | 695,000,000 |
Other income (expense): | |||
Interest expense, net | (199,000,000) | (197,000,000) | (172,000,000) |
Other income (expense), net | (10,000,000) | (7,000,000) | 9,000,000 |
Gain (loss) on derivative instruments, net | (848,000,000) | (81,000,000) | (108,000,000) |
Gain (loss) on sale of equity method investments | 23,000,000 | 0 | 0 |
Gain (loss) on extinguishment of debt | (75,000,000) | (5,000,000) | (56,000,000) |
Income (loss) from equity investments | 15,000,000 | (10,000,000) | (6,000,000) |
Total other income (expense), net | (1,094,000,000) | (300,000,000) | (333,000,000) |
Income (loss) before income taxes | 2,907,000,000 | (5,776,000,000) | 362,000,000 |
Provision for (benefit from) income taxes | 631,000,000 | (1,104,000,000) | 47,000,000 |
Net income (loss) | 2,276,000,000 | (4,672,000,000) | 315,000,000 |
Net income (loss) attributable to non-controlling interest | 94,000,000 | (155,000,000) | 75,000,000 |
Net income (loss) attributable to Diamondback Energy, Inc. | $ 2,182,000,000 | $ (4,517,000,000) | $ 240,000,000 |
Earnings (loss) per common share: | |||
Basic (in dollars per share) | $ 12.35 | $ (28.59) | $ 1.47 |
Diluted (in dollars per share) | $ 12.30 | $ (28.59) | $ 1.47 |
Weighted average common shares outstanding: | |||
Basic (in shares) | 176,643 | 157,976 | 163,493 |
Diluted (in shares) | 177,359 | 157,976 | 163,843 |
Dividends declared per share (in dollars per share) | $ 1.95 | $ 1.5250 | $ 0.9375 |
Oil sales | |||
Revenues: | |||
Revenues | $ 5,396,000,000 | $ 2,410,000,000 | $ 3,554,000,000 |
Natural gas sales | |||
Revenues: | |||
Revenues | 569,000,000 | 107,000,000 | 66,000,000 |
Natural gas liquid sales | |||
Revenues: | |||
Revenues | 782,000,000 | 239,000,000 | 267,000,000 |
Midstream services expense | |||
Revenues: | |||
Revenues | 45,000,000 | 50,000,000 | 64,000,000 |
Costs and expenses: | |||
Cost of goods and services sold | 89,000,000 | 105,000,000 | 91,000,000 |
Gathering and transportation | |||
Costs and expenses: | |||
Cost of goods and services sold | $ 212,000,000 | $ 140,000,000 | $ 88,000,000 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions | Total | Viper Energy Partners LP | Rattler MIdstream LP | Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Non-Controlling Interest | Non-Controlling InterestViper Energy Partners LP | Non-Controlling InterestRattler MIdstream LP |
Balance at beginning of period (in shares) at Dec. 31, 2018 | 164,273,000 | ||||||||
Balance at beginning of period at Dec. 31, 2018 | $ 14,167 | $ 2 | $ 12,936 | $ 762 | $ 467 | ||||
Increase (Decrease) in Stockholders' Equity | |||||||||
Net proceeds from issuance of common units | $ 341 | $ 720 | $ 341 | $ 720 | |||||
Unit-based compensation | 7 | 7 | |||||||
Common units or shares issued for acquisition | 124 | 124 | |||||||
Stock-based compensation | 57 | 57 | |||||||
Cash paid for tax withholding on vested equity awards | (13) | (13) | |||||||
Repurchased shares for share buyback program (in shares) | (6,385,000) | ||||||||
Repurchased shares under buyback program | (598) | (598) | |||||||
Distribution to non-controlling interest | (122) | (122) | |||||||
Dividend paid | (112) | (112) | |||||||
Exercise of stock and unit options and awards of restricted stock (in shares) | 1,114,000 | ||||||||
Exercise of stock and unit options and awards of restricted stock | 8 | 8 | |||||||
Change in ownership of consolidated subsidiaries, net | 12 | (33) | 45 | ||||||
Net income (loss) | 315 | 240 | 75 | ||||||
Balance at end of period (in shares) at Dec. 31, 2019 | 159,002,000 | ||||||||
Balance at end of period at Dec. 31, 2019 | 14,906 | $ 2 | 12,357 | 890 | 1,657 | ||||
Increase (Decrease) in Stockholders' Equity | |||||||||
Unit-based compensation | 10 | 10 | |||||||
Distribution equivalent rights payments | (3) | (1) | (2) | ||||||
Stock-based compensation | 43 | 43 | |||||||
Cash paid for tax withholding on vested equity awards | (7) | (5) | (2) | ||||||
Repurchased shares for share buyback program (in shares) | (1,280,000) | ||||||||
Repurchased shares under buyback program | (98) | (98) | |||||||
Repurchased units under buyback programs | (39) | (39) | |||||||
Distribution to non-controlling interest | (93) | (93) | |||||||
Dividend paid | (236) | (236) | |||||||
Exercise of stock and unit options and awards of restricted stock (in shares) | 366,000 | ||||||||
Exercise of stock and unit options and awards of restricted stock | 1 | 1 | |||||||
Change in ownership of consolidated subsidiaries, net | (8) | 358 | (366) | ||||||
Net income (loss) | $ (4,672) | (4,517) | (155) | ||||||
Balance at end of period (in shares) at Dec. 31, 2020 | 158,088,182 | 158,088,000 | |||||||
Balance at end of period at Dec. 31, 2020 | $ 9,804 | $ 2 | 12,656 | (3,864) | 1,010 | ||||
Increase (Decrease) in Stockholders' Equity | |||||||||
Net proceeds from issuance of common units | $ 337 | $ 337 | |||||||
Unit-based compensation | 11 | 11 | |||||||
Distribution equivalent rights payments | (6) | (4) | (2) | ||||||
Common stock issued for acquisitions (in shares) | 22,795,000 | ||||||||
Common units or shares issued for acquisition | 1,727 | 1,727 | |||||||
Stock-based compensation | 60 | 60 | |||||||
Cash paid for tax withholding on vested equity awards | (8) | (6) | (2) | ||||||
Repurchased shares for share buyback program (in shares) | (4,128,000) | ||||||||
Repurchased shares under buyback program | (431) | (431) | |||||||
Repurchased units under buyback programs | (94) | (94) | |||||||
Distribution to non-controlling interest | (112) | (112) | |||||||
Dividend paid | (312) | (312) | |||||||
Exercise of stock and unit options and awards of restricted stock (in shares) | 796,000 | ||||||||
Exercise of stock and unit options and awards of restricted stock | 12 | 12 | |||||||
Change in ownership of consolidated subsidiaries, net | (19) | 66 | (85) | ||||||
Net income (loss) | $ 2,276 | 2,182 | 94 | ||||||
Balance at end of period (in shares) at Dec. 31, 2021 | 177,551,347 | 177,551,000 | |||||||
Balance at end of period at Dec. 31, 2021 | $ 13,245 | $ 2 | $ 14,084 | $ (1,998) | $ 1,157 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | |||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||||
Cash flows from operating activities: | ||||||
Net income (loss) | $ 2,276,000,000 | $ (4,672,000,000) | $ 315,000,000 | |||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||
Provision for (benefit from) deferred income taxes | 606,000,000 | (1,042,000,000) | 47,000,000 | |||
Impairment of oil and natural gas properties | 0 | 6,021,000,000 | 790,000,000 | |||
Depreciation, depletion, amortization and accretion | 1,275,000,000 | 1,311,000,000 | 1,454,000,000 | |||
(Gain) loss on extinguishment of debt | 75,000,000 | 5,000,000 | 56,000,000 | |||
(Gain) loss on derivative instruments, net | 848,000,000 | 81,000,000 | 108,000,000 | |||
Cash received (paid) on settlement of derivative instruments | (1,247,000,000) | 250,000,000 | 80,000,000 | |||
Equity-based compensation expense | 51,000,000 | 37,000,000 | 48,000,000 | |||
(Gain) loss on sale of equity method investments | (23,000,000) | 0 | 0 | |||
Other | 47,000,000 | 30,000,000 | 8,000,000 | |||
Changes in operating assets and liabilities: | ||||||
Accounts receivable | (196,000,000) | 217,000,000 | (187,000,000) | |||
Income tax receivable | 152,000,000 | (62,000,000) | 0 | |||
Prepaid expenses and other | 20,000,000 | 2,000,000 | 29,000,000 | |||
Accounts payable and accrued liabilities | (41,000,000) | (20,000,000) | (129,000,000) | |||
Revenues and royalties payable | 148,000,000 | (41,000,000) | 135,000,000 | |||
Other | (47,000,000) | 1,000,000 | (15,000,000) | |||
Net cash provided by (used in) operating activities | 3,944,000,000 | 2,118,000,000 | 2,739,000,000 | |||
Cash flows from investing activities: | ||||||
Drilling, completions and infrastructure additions to oil and natural gas properties | (1,457,000,000) | (1,719,000,000) | (2,677,000,000) | |||
Additions to midstream assets | (30,000,000) | (140,000,000) | (244,000,000) | |||
Property acquisitions | (812,000,000) | (185,000,000) | (776,000,000) | |||
Proceeds from sale of assets | 820,000,000 | 63,000,000 | 300,000,000 | |||
Contributions to equity method investments | (114,000,000) | (102,000,000) | (485,000,000) | |||
Distributions from equity method investments | 9,000,000 | 40,000,000 | 0 | |||
Other | 45,000,000 | (58,000,000) | (6,000,000) | |||
Net cash provided by (used in) investing activities | (1,539,000,000) | (2,101,000,000) | (3,888,000,000) | |||
Cash flows from financing activities: | ||||||
Proceeds from borrowings under credit facilities | 1,313,000,000 | 1,130,000,000 | 2,350,000,000 | |||
Repayments under credit facilities | (1,000,000,000) | (1,478,000,000) | (3,718,000,000) | |||
Proceeds from senior notes | 2,200,000,000 | 997,000,000 | 3,469,000,000 | |||
Repayment of senior notes | (3,193,000,000) | (239,000,000) | (1,250,000,000) | |||
Proceeds from (repayments to) joint venture | (20,000,000) | 40,000,000 | 39,000,000 | |||
Premium on extinguishment of debt | (178,000,000) | (2,000,000) | (44,000,000) | |||
Public offering costs | 0 | 0 | (41,000,000) | |||
Proceeds from public offerings | 0 | 0 | 1,106,000,000 | |||
Repurchased shares under buyback program | (431,000,000) | (98,000,000) | (593,000,000) | |||
Repurchased units under buyback program | (94,000,000) | (39,000,000) | 0 | |||
Dividends to stockholders | (312,000,000) | (236,000,000) | (112,000,000) | |||
Distributions to non-controlling interest | (112,000,000) | (93,000,000) | (122,000,000) | |||
Financing portion of net cash received (paid) for derivative instruments | 22,000,000 | 0 | 0 | |||
Other | (36,000,000) | (19,000,000) | (22,000,000) | |||
Net cash provided by (used in) financing activities | (1,841,000,000) | (37,000,000) | 1,062,000,000 | |||
Net increase (decrease) in cash and cash equivalents | 564,000,000 | (20,000,000) | (87,000,000) | |||
Cash, cash equivalents and restricted cash at beginning of period | 108,000,000 | [1] | 128,000,000 | [1] | 215,000,000 | |
Cash, cash equivalents and restricted cash at end of period | [1] | $ 672,000,000 | $ 108,000,000 | $ 128,000,000 | ||
[1] | See Note 2—Summary of Significant Accounting Policies |
DESCRIPTION OF THE BUSINESS AND
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION | DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION Organization and Description of the Business Diamondback Energy, Inc. (“Diamondback” or the “Company”) 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. The wholly-owned subsidiaries of Diamondback, as of December 31, 2021, include Diamondback E&P LLC (“Diamondback E&P”), a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company (“Viper’s General Partner”), Rattler Midstream GP LLC, a Delaware limited liability company (“Rattler’s General Partner”), and QEP Resources, Inc. (“QEP”), a Delaware Corporation. Diamondback O&G LLC (“O&G”), Energen Corporation (“Energen”), Energen Resources Corporation and EGN Services, Inc., former wholly owned subsidiaries of Diamondback, were merged with and into Diamondback E&P LLC effective June 30, 2021 as part of the internal restructuring of the Company’s subsidiaries (the “E&P Merger”). 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. Diamondback’s publicly traded subsidiaries Viper and Rattler are consolidated in the financial statements of the Company. As of December 31, 2021, the Company owned approximately 54% of Viper’s total units outstanding. The Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. As of December 31, 2021, the Company owned approximately 74% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the equity and net income attributable to the Company. The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2021 | |
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 as of the date of the consolidated financial statements. Actual results could differ from those estimates. Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices and the effects of the ongoing COVID-19 pandemic. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those 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, the fair value determination of acquired assets and liabilities assumed, fair value estimates of derivative instruments and estimates of income taxes. Cash, Cash Equivalents and Restricted Cash The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. 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 when collection is doubtful. 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. At December 31, 2021 and 2020, the Company’s allowances for credit losses related to joint interest receivables and credit losses related to sales of oil and natural gas production were not material. Derivative Instruments The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. For commodity derivative instruments and interest rate swaps which have not been designated as hedges for accounting purposes, the Company marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. The Company accounts for its interest rate swaps which have been designated as fair value hedges under the “shortcut” method of accounting. As such, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt. For additional information regarding the Company’s derivative instruments, see Note 15— Derivatives . Oil and Natural Gas Properties 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. 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 and natural liquids. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $8.77, $11.30 and $13.54 for the years ended December 31, 2021, 2020 and 2019, respectively. Depletion expense for oil and natural gas properties was $1.2 billion, $1.2 billion and $1.4 billion for the years ended December 31, 2021, 2020 and 2019, respectively. Under this 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 revenues, 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, 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 write-down is required. For additional information regarding the Company’s impairments on proved oil and natural gas properties, see Note 8— Property and Equipment . 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 Company assesses all items classified as unevaluated property on at least an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. Real Estate Assets Real estate assets are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life. Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset. For additional information regarding the Company’s real estate assets, see Note 7— Real Estate Assets . Other Property, Equipment and Land Other property, equipment and land is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight-line method over their estimated useful lives, which range from three Asset Retirement Obligations The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties. 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. For additional information regarding the Company’s asset retirement obligations, see Note 9— Asset Retirement Obligations . Impairment of Long-Lived Assets Other property and equipment used in operations and midstream assets are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no significant impairment losses for the years ended December 31, 2021, 2020 and 2019. Capitalized Interest The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. See Note 11— Debt for further details. Inventories Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2021 and 2020. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. Debt Issuance Costs Long-term debt includes capitalized costs related to the senior notes, net of accumulated amortization. The costs associated with the senior notes are netted against the senior notes balances and are amortized over the term of the senior notes using the effective interest method. See Note 11— Debt for further details. The costs associated with the Company’s credit facilities are included in other assets on the consolidated balance sheet and are amortized over the term of the facility. Other Accrued Liabilities Other accrued liabilities consist of the following: December 31, 2021 2020 (In millions) Derivative liability payable $ 101 $ 30 Lease operating expenses payable 86 115 Ad valorem taxes payable 70 57 Accrued compensation 48 27 Interest payable 46 37 Midstream operating expenses payable 13 18 Liability for drilling costs prepaid by joint interest partners 10 5 Other 62 13 Total other accrued liabilities $ 436 $ 302 Revenue and Royalties Payable For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties. Non-controlling Interests Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, “Consolidation”, which requires that any differences between the carrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 12— Stockholders' Equity and Earnings Per Share for a discussion of changes of the Company’s ownership interest in consolidated subsidiaries during the year ended December 31, 2021. Revenue Recognition Revenue from Contracts with Customers Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. Oil sales The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations. Natural gas and natural gas liquids sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. Generally, 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 water volumes have been delivered to the frac-water 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 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. 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. 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. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for 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 years ended December 31, 2021, 2020 and 2019 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. Investments The Company accounts for its corporate joint ventures under the equity method of accounting in accordance with Financial Accounting Standards Board Accounting Standards Codification (“ASC”) Topic 323 “Investments — Equity Method and Joint Ventures.” The Company also applies the equity method of accounting to investments of less than 50% in an investee over which the Company exercises significant influence but does not have control and investments of greater than 50% in an investee over which the Company does not exercise significant influence or have control. Under the equity method, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statement of operations. As of December 31, 2021, the Company’s proportionate share of the income or loss from equity method investments is recognized on a one-month lag for all equity method investments. Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There were no material impairments of the Company’s equity investments for the years ended December 31, 2021, 2020 and 2019. For additional information on the Company’s investments, see Note 10— Equity Method Investments . Accounting for Equity-Based Compensation The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper and Rattler have granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner, Rattler’s General Partner and the Company who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 13— Equity-Based Compensation . Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period. Forfeitures for these awards are recognized as they occur. Environmental Compliance and Remediation Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated. Income Taxes The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see Note 14— Income Taxes . Recent Accounting Pronouncements Recently Adopted Pronouncements In December 2019, the FASB issued 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 and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022 with early adoption permitted. The Company continues to evaluate the provisions of this update, but does not believe the adoption will have a material impact on its financial position, results of operations or liquidity. |
REVENUE FROM CONTRACTS WITH CUS
REVENUE FROM CONTRACTS WITH CUSTOMERS | 12 Months Ended |
Dec. 31, 2021 | |
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. The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin: Year Ended December 31, 2021 Midland Basin Delaware Basin Other Total (In millions) Oil sales $ 3,468 $ 1,663 $ 265 $ 5,396 Natural gas sales 327 215 27 569 Natural gas liquid sales 493 249 40 782 Total $ 4,288 $ 2,127 $ 332 $ 6,747 Year Ended December 31, 2020 Midland Basin Delaware Basin Other Total (In millions) Oil sales $ 1,393 $ 1,011 $ 6 $ 2,410 Natural gas sales 56 50 1 107 Natural gas liquid sales 138 100 1 239 Total $ 1,587 $ 1,161 $ 8 $ 2,756 Three Months Ended December 31, 2019 Midland Basin Delaware Basin Other Total (In millions) Oil sales $ 2,139 $ 1,351 $ 64 $ 3,554 Natural gas sales 32 33 1 66 Natural gas liquid sales 154 110 3 267 Total $ 2,325 $ 1,494 $ 68 $ 3,887 Customers The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2021, three purchasers each accounted for more than 10% of our revenue: Vitol Inc. (“Vitol”) (21%); Shell Trading (USA) Company (“Shell”) (19%); and Plains Marketing LP (“Plains”) (12%). For the year ended December 31, 2020, four purchasers each accounted for more than 10% of the Company’s revenue: Vitol (26%); Shell (22%); Plains (20%); and Trafigura Trading LLC (11%). For the year ended December 31, 2019, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (27%); Plains (23%); and Vitol (15%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended |
Dec. 31, 2021 | |
Business Combinations And Divestitures [Abstract] | |
ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES 2021 Activity Guidon Operating LLC On February 26, 2021, the Company closed on its acquisition of all leasehold interests and related assets of Guidon Operating LLC (the “Guidon Acquisition”) which include approximately 32,500 net acres in the Northern Midland Basin in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash. The cash portion of this transaction was funded through a combination of cash on hand and borrowings under the Company’s credit facility. As a result of the Guidon Acquisition, the Company added approximately 210 gross producing wells. The following table presents the acquisition consideration paid in the Guidon Acquisition (in millions, except per share data, shares in thousands): Consideration: Shares of Diamondback common stock issued at closing 10,676 Closing price per share of Diamondback common stock on the closing date $ 69.28 Fair value of Diamondback common stock issued $ 740 Cash consideration 375 Total consideration (including fair value of Diamondback common stock issued) $ 1,115 Purchase Price Allocation The Guidon Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the Guidon Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date and may revise the value of the assets and liabilities as appropriate within that time frame. Through December 31, 2021, there have been no material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021. The following table sets forth the Company’s preliminary purchase price allocation (in millions): Total consideration $ 1,115 Fair value of liabilities assumed: Asset retirement obligations 9 Fair value of assets acquired: Oil and gas properties 1,110 Midstream assets 14 Amount attributable to assets acquired 1,124 Net assets acquired and liabilities assumed $ 1,115 Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs. With the completion of the Guidon Acquisition, the Company acquired proved properties of $537 million and unproved properties of $573 million. The results of operations attributable to the Guidon Acquisition since the acquisition date have been included in the consolidated statements of operations and include $345 million of total revenue and $170 million of net income for the year ended December 31, 2021. QEP Resources, Inc. On March 17, 2021, the Company completed its acquisition of QEP in an all-stock transaction (the “QEP Merger”). The addition of QEP’s assets increased the Company’s net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the QEP Merger, each eligible share of QEP common stock issued and outstanding immediately prior to the effective time converted into the right to receive 0.050 of a share of Diamondback common stock, with cash being paid in lieu of any fractional shares (the “merger consideration”). At the closing date of the QEP Merger, the carrying value of QEP’s outstanding debt was approximately $1.6 billion. See Note 11— Debt for further discussion. The following table presents the acquisition consideration paid to QEP stockholders in the QEP Merger (in millions, except per share data, shares in thousands): Consideration: Eligible shares of QEP common stock converted into shares of Diamondback common stock 238,153 Shares of QEP equity awards included in precombination consideration 4,221 Total shares of QEP common stock eligible for merger consideration 242,374 Exchange ratio 0.050 Shares of Diamondback common stock issued as merger consideration 12,119 Closing price per share of Diamondback common stock $ 81.41 Total consideration (fair value of the Company's common stock issued) $ 987 Purchase Price Allocation The QEP Merger has been accounted for as a business combination using the acquisition method. The following table represents the preliminary allocation of the total purchase price for the acquisition of QEP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, certain data necessary to complete the purchase price allocation is not yet available and includes, but is not limited to, final tax returns that provide the underlying tax basis of QEP’s assets and liabilities and final valuations of the acquired oil and natural gas properties. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. The following table sets forth the Company’s preliminary purchase price allocation (in millions): Total consideration $ 987 Fair value of liabilities assumed: Accounts payable - trade $ 26 Accrued capital expenditures 38 Other accrued liabilities 107 Revenues and royalties payable 67 Derivative instruments 242 Long-term debt 1,710 Asset retirement obligations 54 Other long-term liabilities 63 Amount attributable to liabilities assumed $ 2,307 Fair value of assets acquired: Cash, cash equivalents and restricted cash $ 22 Accounts receivable - joint interest and other, net 87 Accounts receivable - oil and natural gas sales, net 44 Inventories 18 Income tax receivable 33 Prepaid expenses and other current assets 7 Oil and natural gas properties 2,927 Other property, equipment and land 10 Deferred income taxes 40 Other assets 106 Amount attributable to assets acquired 3,294 Net assets acquired and liabilities assumed $ 987 The purchase price allocation above is based on estimates of the fair values of the assets and liabilities of QEP as of the closing date of the QEP Merger. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs. The fair value of acquired property and equipment, including midstream assets classified in oil and natural gas properties, is based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of QEP’s outstanding senior unsecured notes was based on unadjusted quoted prices in an active market, which are considered Level 1 inputs. The value of derivative instruments was based on observable inputs including forward commodity price curves which are considered Level 2 inputs. Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed. With the completion of the QEP Merger, the Company acquired proved properties of $2.0 billion and unproved properties of $742 million, primarily in the Midland Basin and the Williston Basin. The Williston Basin assets were divested in October 2021 as discussed further below. Through December 31, 2021, the fair value allocated to proved properties acquired in the QEP Merger has decreased by $300 million and the fair value allocated to unproved properties has increased by $300 million based on management’s continuing assessment of the inputs utilized in the fair value estimates discussed above. There have been no other material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021. The results of operations attributable to the QEP Merger since the acquisition date have been included in the consolidated statements of operations and include $1.1 billion of total revenue and $455 million of net income for the year ended December 31, 2021. Pro Forma Financial Information The following unaudited summary pro forma financial information for the years ended December 31, 2021 and 2020 has been prepared to give effect to the QEP Merger and the Guidon Acquisition as if they had occurred on January 1, 2020. The unaudited pro forma financial information does not purport to be indicative of what the combined company’s results of operations would have been if these transactions had occurred on the dates indicated, nor is it indicative of the future financial position or results of operations of the combined company. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for QEP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and the purchase price allocated to property, plant, and equipment as well as adjustments to interest expense and the provision for (benefit from) income taxes. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company for the QEP Merger and the Guidon Acquisition of approximately $78 million for the year ended December 31, 2021 and acquisition-related costs incurred by QEP of $31 million through the closing date of the QEP Merger. These acquisition-related costs primarily consist of one-time severance costs and the accelerated or change-in-control vesting of certain QEP share-based awards for former QEP employees based on the terms of the merger agreement relating to the QEP Merger and other bank, legal and advisory fees. The pro forma results of operations do not include any cost savings or other synergies that may result from the QEP Merger and the Guidon Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. Year Ended December 31, 2021 2020 (In millions, except per share amounts) Revenues $ 7,069 $ 3,727 Income (loss) from operations $ 4,182 $ (5,771) Net income (loss) $ 2,186 $ (4,641) Basic earnings per common share $ 12.09 $ (25.67) Diluted earnings per common share $ 12.05 $ (25.67) Divestitures of Certain Non-Core Assets On June 3, 2021 and June 7, 2021, respectively, the Company closed transactions to divest certain non-core Permian assets including over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county, Texas and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for combined net cash proceeds of $82 million, after customary closing adjustments. The Company used its net proceeds from these transactions toward debt reduction. Williston Basin Divestiture On October 21, 2021, the Company completed the divestiture of its Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres, to Oasis Petroleum Inc., for net cash proceeds of approximately $586 million, after customary closing adjustments. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale. The Company used its net proceeds from this transaction toward debt reduction. Gas Gathering Assets Divestiture On November 1, 2021, the Company completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC, an affiliate of Brazos Midstream (“Brazos”), for net cash proceeds of approximately $54 million, after customary closing adjustments. 2021 Drop Down Transaction On December 1, 2021, Diamondback completed the sale of certain water midstream assets to Rattler in exchange for cash proceeds of approximately $160 million, in a drop down transaction (the “Drop Down”). The midstream assets consist primarily of produced water gathering and disposal systems, produced water recycling facilities, and sourced water gathering and storage assets acquired by the Company through the Guidon Acquisition and the QEP Merger with a carrying value of approximately $160 million. The Company and Rattler have also mutually agreed to amend their commercial agreements covering produced water gathering and disposal and sourced water gathering services to add certain Diamondback leasehold acreage to Rattler’s dedication. The Drop Down transaction was accounted for as a transaction between entities under common control. Viper’s Swallowtail Acquisition On October 1, 2021, Viper acquired certain mineral and royalty interests from the Swallowtail entities pursuant to a definitive purchase and sale agreement for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres primarily in the Northern Midland Basin, of which approximately 62% are operated by Diamondback. The Swallowtail Acquisition had an effective date of August 1, 2021. The cash portion of this transaction was funded through a combination of Viper’s cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility. Rattler’s WTG Joint Venture Acquisition On October 5, 2021, Rattler and a private affiliate of an investment fund formed the WTG joint venture. Rattler contributed approximately $104 million in cash for a 25% membership interest in the WTG joint venture, which then completed the acquisition of a majority interest in WTG Midstream from West Texas Gas, Inc. and its affiliates. WTG Midstream’s assets primarily consist of an interconnected gas gathering system and six major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned. Rattler’s Gas Gathering Divestiture On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos for aggregate total gross potential consideration of $93 million, consisting of (i) $83 million due at closing, after customary closing adjustments, (ii) a $5 million contingent payment due in 2023 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022, and (iii) a $5 million contingent payment due in 2024 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022 and 2023. The contingent payments will be recorded if and when they become realizable. 2020 Activity Viper’s Acquisition of Certain Mineral and Royalty Interests During the year ended December 31, 2020, Viper acquired, from unrelated third-party sellers, mineral and royalty interests representing 4,948 gross (417 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $64 million, including post-closing adjustments. Viper funded these acquisitions with cash on hand and borrowings under Viper LLC’s revolving credit facility. 2019 Activity Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen On May 23, 2019, the Company completed its divestiture of 6,589 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in its merger with Energen, for an aggregate sale price of $37 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate. On July 1, 2019, the Company completed its divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the merger with Energen, for an aggregate sale price of $285 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate. 2019 Drop-Down Transaction On July 29, 2019, the Company entered into a definitive purchase agreement to divest certain mineral and royalty interests to Viper for approximately 18 million of Viper’s newly-issued Class B units, approximately 18 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits. The mineral and royalty interests divested in the drop down transaction represented approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% were operated by the Company, and had an average net royalty interest of approximately 3.2%. The drop down transaction closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the drop down transaction through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility. |
VIPER ENERGY PARTNERS LP
VIPER ENERGY PARTNERS LP | 12 Months Ended |
Dec. 31, 2021 | |
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 to, among other things, own, acquire and exploit oil and natural gas properties in the Permian Basin in North America. Viper LLC (“Viper’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of viper. As of December 31, 2021, Diamondback owned approximately 54% of Viper’s total units outstanding. In March 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Viper received net proceeds from this offering of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. There were no equity offerings during the years ended December 31, 2021 and 2020. During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $101 million, $62 million and $133 million, respectively, in respect of its interests in Viper and Viper LLC. The Company is party to a partnership agreement and tax sharing agreement with Viper which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019. See Note 4— Acquisitions and Divestitures for discussions of Viper’s acquisitions and divestitures. Implementation of Viper’s Common Unit Repurchase Program On November 6, 2020, the board of directors of Viper’s general partner approved a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units. The common unit repurchase program was initially authorized to extended through December 31, 2021, but in November 2021, the board of directors of Viper’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Viper repurchased approximately $46 million of its common units under its repurchase program. As of December 31, 2021, $80 million remained available for use to repurchase common units under Viper’s common unit repurchase program. Viper LLC’s Revolving Credit Facility Viper has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 11— 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 December 31, 2021, Diamondback owned approximately 74% of Rattler’s total units outstanding. Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 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. 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. During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $97 million, $115 million and $36 million, respectively, in respect of its interests in Rattler and Rattler Midstream GP LLC. The Company is party to a partnership agreement, services and secondment agreement and tax sharing agreement with Rattler which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019. See Note 4— Acquisitions and Divestitures for discussions of Rattler’s acquisitions and divestitures. Implementation of Rattler’s Common Unit Repurchase Program On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units. The common unit repurchase program was initially authorized to extend through December 31, 2021, but in October 2021, the board of directors of Rattler’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Rattler repurchased approximately $48 million of its common units under its repurchase program. As of December 31, 2021, $88 million remained available for use to repurchase common units under Rattler’s common unit repurchase program. Rattler LLC’s Revolving Credit Facility Rattler LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 11— Debt for a description of this credit facility. |
RATTLER MIDSTREAM LP
RATTLER MIDSTREAM LP | 12 Months Ended |
Dec. 31, 2021 | |
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 to, among other things, own, acquire and exploit oil and natural gas properties in the Permian Basin in North America. Viper LLC (“Viper’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of viper. As of December 31, 2021, Diamondback owned approximately 54% of Viper’s total units outstanding. In March 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Viper received net proceeds from this offering of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. There were no equity offerings during the years ended December 31, 2021 and 2020. During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $101 million, $62 million and $133 million, respectively, in respect of its interests in Viper and Viper LLC. The Company is party to a partnership agreement and tax sharing agreement with Viper which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019. See Note 4— Acquisitions and Divestitures for discussions of Viper’s acquisitions and divestitures. Implementation of Viper’s Common Unit Repurchase Program On November 6, 2020, the board of directors of Viper’s general partner approved a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units. The common unit repurchase program was initially authorized to extended through December 31, 2021, but in November 2021, the board of directors of Viper’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Viper repurchased approximately $46 million of its common units under its repurchase program. As of December 31, 2021, $80 million remained available for use to repurchase common units under Viper’s common unit repurchase program. Viper LLC’s Revolving Credit Facility Viper has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 11— 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 December 31, 2021, Diamondback owned approximately 74% of Rattler’s total units outstanding. Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 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. 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. During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $97 million, $115 million and $36 million, respectively, in respect of its interests in Rattler and Rattler Midstream GP LLC. The Company is party to a partnership agreement, services and secondment agreement and tax sharing agreement with Rattler which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019. See Note 4— Acquisitions and Divestitures for discussions of Rattler’s acquisitions and divestitures. Implementation of Rattler’s Common Unit Repurchase Program On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units. The common unit repurchase program was initially authorized to extend through December 31, 2021, but in October 2021, the board of directors of Rattler’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Rattler repurchased approximately $48 million of its common units under its repurchase program. As of December 31, 2021, $88 million remained available for use to repurchase common units under Rattler’s common unit repurchase program. Rattler LLC’s Revolving Credit Facility Rattler LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 11— Debt for a description of this credit facility. |
REAL ESTATE ASSETS
REAL ESTATE ASSETS | 12 Months Ended |
Dec. 31, 2021 | |
Real Estate [Abstract] | |
REAL ESTATE ASSETS | REAL ESTATE ASSETS The following schedules present the cost and related accumulated depreciation related to Diamondback’s significant real estate assets: Estimated Useful Lives December 31, 2021 2020 (Years) (In millions) Buildings 20-30 $ 95 $ 102 Tenant improvements 5 - 15 4 5 Land N/A 1 2 Land improvements 5 - 15 1 1 Total real estate assets 101 110 Less: accumulated depreciation (16) (13) Total investment in land and buildings, net $ 85 $ 97 |
PROPERTY AND EQUIPMENT
PROPERTY AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY AND EQUIPMENT | PROPERTY AND EQUIPMENT Property and equipment includes the following: December 31, 2021 2020 (In millions) Oil and natural gas properties: Subject to depletion $ 24,418 $ 19,884 Not subject to depletion 8,496 7,493 Gross oil and natural gas properties 32,914 27,377 Accumulated depletion (5,434) (4,237) Accumulated impairment (7,954) (7,954) Oil and natural gas properties, net 19,526 15,186 Midstream assets 1,076 1,013 Other property, equipment and land 174 138 Accumulated depreciation and impairment (157) (123) Total property and equipment, net $ 20,619 $ 16,214 Balance of costs not subject to depletion: Incurred in 2021 $ 1,688 Incurred in 2020 71 Incurred in 2019 422 Thereafter 6,315 Total not subject to depletion $ 8,496 Capitalized internal costs were approximately $60 million, $53 million and $49 million for the years ended December 31, 2021, 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 ten years. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter which determines a limit, or ceiling, on the book value of proved oil and natural gas properties. No impairment expense was recorded for the year ended December 31, 2021. The Company recorded non-cash ceiling test impairments for the years ended December 31, 2020 and 2019 of $6.0 billion and $790 million, respectively, which are included in accumulated depletion, depreciation, amortization and impairment on the consolidated balance sheet. The impairment charge affected the Company’s reported net income but did not reduce its cash flow. In connection with the QEP Merger and the Guidon Acquisition, the Company recorded the oil and natural gas properties acquired at fair value, based on forward strip oil and natural gas pricing existing at the closing date of the respective transactions, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, the Company requested and received a waiver from the SEC to exclude the properties acquired from the ceiling test calculation for the quarter ended March 31, 2021. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had the Company not received a waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded for such period. Management affirmed there has not been a decline in the fair value of these acquired assets. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively. 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 decline as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. Given the rate of change impacting the oil and natural 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 December 31, 2021, there were $135 million in exploration costs and development costs and $124 million in capitalized interest that are not subject to depletion. At December 31, 2020, there were $85 million in exploration costs and development costs and $51 million capitalized interest that were not subject to depletion. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2021 | |
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: Year Ended December 31, 2021 2020 (In millions) Asset retirement obligations, beginning of period $ 109 $ 94 Additional liabilities incurred 11 13 Liabilities acquired 65 2 Liabilities settled and divested (36) (8) Accretion expense 9 7 Revisions in estimated liabilities 13 1 Asset retirement obligations, end of period 171 109 Less: current portion (1) 5 1 Asset retirement obligations - long-term $ 166 $ 108 (1) The current portion of the asset retirement obligation is included in other accrued liabilities in the Company’s consolidated balance sheets. 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. |
EQUITY METHOD INVESTMENTS
EQUITY METHOD INVESTMENTS | 12 Months Ended |
Dec. 31, 2021 | |
Equity Method Investments and Joint Ventures [Abstract] | |
EQUITY METHOD INVESTMENTS | EQUITY METHOD INVESTMENTS At December 31, 2021 and 2020, Rattler had the following investments: Ownership Interest December 31, 2021 December 31, 2020 (In millions) EPIC Crude Holdings, LP 10 % $ 107 $ 121 Gray Oak Pipeline, LLC 10 % 121 130 Wink to Webster Pipeline LLC (1) 4 % 86 83 OMOG JV LLC 60 % 188 194 Amarillo Rattler, LLC (2) — % — 5 Remuda Midstream Holdings LLC 25 % 111 — Total $ 613 $ 533 (1) The Wink to Webster joint venture is developing a crude oil pipeline (the “Wink to Webster pipeline”). The Wink to Webster pipeline’s main segment began interim service operation in the fourth quarter of 2020, and the joint venture is expected to begin full commercial operations in the first quarter of 2022. (2) The ownership interest in Amarillo Rattler was 50% at December 31, 2020. See Note 4— Acquisitions and D ivestitures for discussion regarding the sale of this equity method investment during the second quarter of 2021. Income (loss) and distributions from Rattler’s equity method investees were not material for the years ended December 31, 2021, 2020 or 2019. The Company reviews its equity method investments to determine if a loss in value which is other than temporary has occurred when events indicate the carrying value of the investment may not be recoverable. Based on indicators present at December 31, 2021, the Company reviewed its investment in EPIC and determined the carrying value of the investment was less than its estimated fair value due to a reduction in expected future cash flow. However, based on the Company’s review of various factors leading to the decline in the fair value of the investment, it was determined the carrying value of the EPIC investment will recover in the near term and therefore an other than temporary impairment in the carrying value of the EPIC equity method investment did not exist at December 31, 2021. However, should the conclusions on certain factors included in the Company’s analysis, including estimates of EPIC’s future cash flows, change, the Company may recognize an impairment that could materially impact it’s consolidated financial statements. No significant impairments were recorded for Rattler’s equity method investments for the years ended December 31, 2020 or 2019. Rattler’s investees all serve customers in the oil and natural gas industry, which experienced economic challenges due to the COVID-19 pandemic and other macroeconomic factors during 2020 prior to recovering in 2021. If similar economic challenges occur in future interim periods, it could result in circumstances requiring Rattler to record potentially material impairment charges on its equity method investments. |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
DEBT | DEBT The Company’s debt consisted of the following as of the dates indicated: December 31, 2021 2020 (In millions) 4.625% Notes due 2021 (1) $ — $ 191 5.375% Senior Notes due 2022 (3) 25 — 7.320% Medium-term Notes, Series A, due 2022 (4) 20 20 5.250% Senior Notes due 2023 (3) 10 — 2.875% Senior Notes due 2024 1,000 1,000 4.750% Senior Notes due 2025 500 500 5.375% Senior Notes due 2025 (2) — 800 3.250% Senior Notes due 2026 800 800 5.625% Senior Notes due 2026 (3) 14 — 7.125% Medium-term Notes, Series B, due 2028 (4) 100 100 3.500% Senior Notes due 2029 1,200 1,200 3.125% Senior Notes due 2031 900 — 4.400% Senior Notes due 2051 650 — DrillCo Agreement (5) 58 79 Unamortized debt issuance costs (31) (29) Unamortized discount costs (28) (27) Unamortized premium costs 8 15 Fair value of interest rate swap agreements (6) (18) — Revolving credit facility — 23 Viper revolving credit facility 304 84 Viper 5.375% Senior Notes due 2027 480 480 Rattler revolving credit facility 195 79 Rattler 5.625% Senior Notes due 2025 500 500 Total debt, net 6,687 5,815 Less: current maturities of long-term debt (45) (191) Total long-term debt $ 6,642 $ 5,624 (1) In June 2021, the Company redeemed the remaining $191 million principal amount of outstanding legacy 4.625% senior notes due September 1, 2021 of Energen. (2) In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes. (3) At the effective time of the QEP Merger, QEP became a wholly owned subsidiary of the Company and remained the issuer of these senior notes. (4) In November 2018, Energen became the Company’s wholly owned subsidiary and remained the issuer of these senior notes. In connection with the E&P Merger, Diamondback E&P became the successor issuer under the indenture. (5) The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. As of December 31, 2021, the amount due to CEMOF related to this alliance was $58 million. As of December 31, 2021, fifteen joint wells under this agreement have been drilled and completed. (6) The Company has two interest rate swap agreements in place on the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. See Note 15— Derivatives for additional information on the Company’s interest rate swaps designated as fair value hedges. Debt maturities as of December 31, 2021, excluding debt issuance costs, premiums and discounts and fair value of interest rate swap premiums are as follows: Year Ending December 31, (In millions) 2022 $ 45 2023 10 2024 1,195 2025 1,304 2026 814 Thereafter 3,388 Total $ 6,756 References in this section to the Company shall mean Diamondback Energy, Inc. and Diamondback E&P, collectively, unless otherwise specified. Second Amended and Restated Credit Facility The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 2, 2021, Diamondback Energy, Inc., as parent guarantor, and O&G, as borrower (the “Borrower”), entered into a twelfth amendment (the “Amendment”) to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, with Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto. The Amendment, among other things, (i) extended the maturity date to June 2, 2026, which may be further extended by two one-year extensions pursuant to the terms set forth in the credit agreement, (ii) decreased the total revolving loan commitments from $2.0 billion to $1.6 billion, which may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion) upon election of the Borrower, subject to obtaining additional lender commitments and satisfaction of customary conditions pursuant to the terms set forth in the credit agreement, (iii) added the ability of the Borrower to incur up to $100 million of the loans under the credit agreement as swingline loans and (iv) changed the interest rate applicable to the loans and certain fees payable under the credit agreement. Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Borrower that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. After giving effect to the Amendment, (i) the applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate, and from 1.250% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.150% to 0.350% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on certain ratings agencies’ ratings of the Company’s long-term senior unsecured debt. On June 30, 2021, Diamondback E&P, as successor borrower to Diamondback O&G LLC, Diamondback Energy, Inc., as parent guarantor, and the Administrative Agent entered into a Successor Borrower Joinder Agreement (the “Joinder Agreement”) in connection with the E&P Merger. Pursuant to the Joinder Agreement, Diamondback E&P assumed all obligations (including, without limitation, all of the indebtedness) of O&G as the borrower under the credit agreement, the Second Amended and Restated Guaranty Agreement, dated as of November 20, 2019, made by O&G and Diamondback Energy, Inc., and the other documents entered into connection therewith. As of December 31, 2021, the maximum credit amount available under the credit agreement is $1.6 billion which was fully available for future borrowings, except for an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under the credit agreement on a dollar for dollar basis. The weighted average interest rate on borrowings under the credit agreement was 1.67%, 2.02% and 4.10% for the years ended December 31, 2021, 2020 and 2019, respectively. Loan principal may be optionally repaid 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 December 31, 2021 and 2020, the Company was in compliance with all financial maintenance 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. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. 2021 Issuances of Notes On March 24, 2021, Diamondback Energy, Inc. issued $650 million aggregate principal amount of 0.900% Senior Notes due March 24, 2023 (the “2023 Notes”), $900 million aggregate principal amount of 3.125% Senior Notes due March 24, 2031 (the “2031 Notes”) and $650 million aggregate principal amount of 4.400% Senior Notes due March 24, 2051 (the “2051 Notes” and together with the 2023 Notes and the 2031 Notes, the “March 2021 Notes”) and received proceeds, net of $24 million in debt issuance costs and discounts, of $2.18 billion. The net proceeds were primarily used to fund the repurchase of other senior notes outstanding as discussed further below. Interest on the March 2021 Notes is payable semi-annually in March and September, beginning in September 2021. The Company redeemed the 2023 Notes in November 2021 as discussed in “—Redemptions of Diamondback Notes” below. The 2031 Notes and the 2051 Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P. The 2031 Notes and the 2051 Notes are senior in right of payment to any of the Company’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s existing and future senior indebtedness. The 2031 Notes and the 2051 Notes are effectively subordinated to the Company’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all of the existing and future indebtedness and other liabilities of the Company’s subsidiaries other than Diamondback E&P. The Company may redeem (i) the 2031 Notes in whole or in part at any time prior to December 24, 2030 and (ii) the 2051 Notes in whole or in part at any time prior to September 24, 2050, in each case at the redemption price set forth in the IG Indenture. If the 2031 Notes or the 2051 Notes are redeemed on or after the dates noted above, in each case, they may be redeemed at a redemption price equal to 100% of the principal amount of the 2031 Notes or 2051 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 IG Indenture, holders may require the Company to purchase some or all of its 2031 Notes or 2051 Notes for cash at a price equal to 101% of the principal amount being purchased, plus accrued and unpaid interest, if any, to the date of purchase. 2021 Redemptions of Notes On March 17, 2021, at the time of the QEP Merger discussed in Note 4— Acquisitions and Divestitures , QEP had outstanding debt at fair values consisting of $478 million of 5.375% Senior Notes due 2022 (the “QEP 2022 Notes”), $673 million of 5.250% Senior Notes due 2023 (the “QEP 2023 Notes”) and $558 million of 5.625% Senior Notes due 2026 (the “QEP 2026 Notes” and together with the QEP 2022 Notes and QEP 2023 Notes, the “QEP Notes”). Subsequent to the QEP Merger, in March 2021, the Company repurchased pursuant to tender offers commenced by the Company, approximately $1.65 billion in fair value carrying amount of the QEP Notes for total cash consideration of $1.7 billion, including redemption and early premium fees of $152 million, which resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of approximately $47 million. The aggregate fair value of the QEP Notes repurchased consisted of (i) $453 million, or 94.65%, of the outstanding fair value carrying amount of the QEP 2022 Notes, (ii) $663 million, or 98.43%, of the outstanding fair value carrying amount of the QEP 2023 Notes and (iii) $538 million, or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes. In March 2021, the Company also repurchased an aggregate of $368 million principal amount of its 5.375% 2025 Senior Notes representing approximately 45.97% of the outstanding 2025 Senior Notes, for total cash consideration of $381 million, including redemption and early premium fees of $13 million. This resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of $14 million. The Company funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above. In connection with the tender offers to repurchase the QEP Notes discussed above, the Company also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the indenture under which the QEP Notes were issued. The Company received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments. In June 2021, the Company redeemed the remaining $191 million principal amount of the outstanding 4.625% senior notes of Energen due on September 1, 2021. The Company recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the redeemed notes. The Company funded the redemption with internally generated cash flow from operations as well as proceeds from the divestitures of certain non-core assets as discussed in Note 4— Acquisitions and Divestitures . In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes for total cash consideration of $449 million, including redemption and early premium fees of $12 million, which resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of $12 million. The Company funded the redemption with cash on hand and borrowings under its revolving credit facility. On November 1, 2021, the Company redeemed the aggregate $650 million principal amount of its outstanding 2023 Notes at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. The Company funded the redemption with proceeds received from the divestiture of its Williston Basin assets and cash on hand. Viper’s Credit Agreement On June 2, 2021, Viper LLC entered into the seventh amendment to the existing credit agreement, which (i) extended the maturity date under the credit agreement to June 2, 2025, (ii) changed the interest rates applicable to the loans under the credit agreement and certain fees payable under the credit agreement, and (iii) added a financial covenant requiring the ratio of secured debt to EBITDAX (as each is defined in the credit agreement) to be not greater than 2.50 to 1.0. On November 15, 2021, Viper LLC entered into the eighth amendment to the existing credit agreement, which maintained the maximum amount of the revolving credit facility of $2.0 billion, reaffirmed the borrowing base of $580 million based on Viper LLC’s oil and natural gas reserves and other factors and added new provisions that allow Viper LLC to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be redetermined semi-annually in May and November. In addition, Viper LLC and Wells Fargo may each request up to three interim redeterminations of the borrowing base during any 12-month period. As of December 31, 2021, Viper LLC had elected a commitment amount of $500 million, with $304 million of outstanding borrowings and $196 million available for future borrowings under the Viper credit agreement. The outstanding borrowings under the Viper credit agreement bear interest at a 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 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternate base rate and from 2.00% to 3.00% per annum in the case of LIBOR, in each case depending on the amount of loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment 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 is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary 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. The loan is secured by substantially all of the assets of Viper and Viper LLC. The weighted average interest rates on borrowings under the Viper credit agreement were 2.35%, 2.20%, and 4.51% for the years ended December 31, 2021, 2020 and 2019, respectively. 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, excess cash 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 in the Viper credit agreement Not less than 1.0 to 1.0 Ratio of secured debt to EBITDAX, as defined in the Viper credit agreement Not greater than 2.5 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. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of December 31, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement. 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. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend. 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, as amended, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary breakage), and is required to be paid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC, Rattler Ajax Processing LLC, Rattler WTG LLC and Rattler Holdings and is secured by substantially all of the assets of Rattler and Rattler LLC. On December 21, 2021, Rattler, as parent, entered into a third amendment (the “Third Amendment”) to the Credit Agreement, dated as of May 28, 2019, with Rattler LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto to, among other things, (i) permit the Rattler internal reorganization, including, without limitation, the formation of Rattler Holdings LLC (“Rattler Holdings”) and the contribution of 100% of the limited liability company interests Rattler held in Rattler LLC to Rattler Holdings and (ii) provide for the addition of Rattler Holdings as a guarantor and restricted subsidiary. As of December 31, 2021, Rattler LLC had $195 million of outstanding borrowings and $405 million available for future borrowings under the Rattler credit agreement. The outstanding borrowings under the Rattler credit agreement bear interest at a 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 weighted average interest rates on borrowings under the Rattler credit agreement were 1.41%, 2.10%, and 3.13% for the years ended December 31, 2021, 2020 and 2019, respectively. 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 or Rattler LLC to issue unsecured debt securities and an exception allowing payment of distributions if no 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 Financial Covenant Election (as defined in the Rattler credit agreement) is made, 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 As of December 31, 2021, Rattler LLC was 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. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial maintenance covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. With certain specified exceptions, the terms and provisions of the Credit Agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend. Interest expense The following amounts have been incurred and charged to interest expense for the years ended December 31, 2021, 2020 and 2019: Year Ended December 31, 2021 2020 2019 (In millions) Interest expense $ 277 $ 250 $ 235 Other fees and expenses 11 6 4 Less: interest income 1 4 1 Less: capitalized interest 88 55 66 Interest expense, net $ 199 $ 197 $ 172 |
STOCKHOLDERS_ EQUITY AND EARNIN
STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE | STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE Diamondback did not complete any equity offerings during the years ended December 31, 2021, 2020 and 2019. Stock Repurchase Programs In September 2021, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock. 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 year ended December 31, 2021, the Company repurchased approximately $431 million of common stock under this repurchase program, respectively. As of December 31, 2021, $1.6 billion remained available for use to repurchase shares under the Company’s common 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 were made from time to time in open market or privately negotiated transactions, and were subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program did not require the Company to acquire any specific number of shares. During the years ended December 31, 2020 and 2019, the Company repurchased $98 million and $598 million, respectively, of its common stock under the repurchase program. The repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020. Change in Ownership of Consolidated Subsidiaries Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. The Company’s ownership percentage in Viper and Rattler change as a result of public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on its units. These changes in ownership percentage and the disproportionate allocation of net income to the Company result in the difference between the Company’s share of the underlying net book value in Viper and Rattler. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period: Year Ended December 31, 2021 2020 2019 (In millions) Net income (loss) attributable to the Company $ 2,182 $ (4,517) $ 240 Change in ownership of consolidated subsidiaries (1) 66 358 (33) Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest $ 2,248 $ (4,159) $ 207 (1) The year ended December 31, 2020 includes an adjustment to non-controlling interest for Rattler of $329 million and to additional paid-in-capital of $329 million to reflect the ownership structure that was effective at June 30, 2020. The adjustment had no impact on the consolidated statement of income or consolidated statement of cash flows for the year ended December 31, 2020. Viper Unitholders’ Equity For information regarding Viper’s significant equity transactions, refer to Note 5— Viper Energy Partners LP . Rattler Unitholders’ Equity For information regarding Rattler’s significant equity transactions, refer to Note 6— Rattler Midstream LP . Earnings (Loss) Per Share The Company’s basic earnings (loss) 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, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiaries. A reconciliation of the components of basic and diluted earnings (loss) per common share is presented in the table below: Year Ended December 31, 2021 2020 2019 (In millions, except per share amounts, shares in thousands) Net income (loss) attributable to common stock $ 2,182 $ (4,517) $ 240 Weighted average common shares outstanding: Basic weighted average common shares outstanding 176,643 157,976 163,493 Effect of dilutive securities: Potential common shares issuable (1)(2) 716 — 350 Diluted weighted average common shares outstanding 177,359 157,976 163,843 Basic net income (loss) attributable to common stock $ 12.35 $ (28.59) $ 1.47 Diluted net income (loss) attributable to common stock $ 12.30 $ (28.59) $ 1.47 (1) For the year ended December 31, 2021, there were 115,865 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method. |
EQUITY-BASED COMPENSATION
EQUITY-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
EQUITY-BASED COMPENSATION | EQUITY-BASED COMPENSATION On June 3, 2021, the Company’s stockholders approved and adopted the Company’s 2021 amended and restated equity incentive plan (the “Equity Plan”), which, among other things, increased total shares authorized for issuance from 8.3 million to 11.8 million. At December 31, 2021, the Company had 6.9 million shares of common stock available for future grants. Under the Equity Plan, approved by the Board of Directors, the Company is authorized to issue incentive and non-statutory stock options, restricted stock awards and restricted stock units, performance awards and stock appreciation rights to eligible employees. At December 31, 2021, the Company had outstanding restricted stock units, performance-based restricted stock units, immaterial amounts of restricted share awards which were assumed in connection with the QEP Merger, and immaterial amounts of stock options and stock appreciation rights. The following table presents the effects of the equity and stock based compensation plans and related costs: Year Ended December 31, 2021 2020 2019 (In millions) General and administrative expenses $ 51 $ 37 $ 48 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties $ 20 $ 16 $ 17 Restricted Stock Units The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents the Company’s restricted stock unit activity under the Equity Plan during the year ended December 31, 2021: Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2020 1,113,480 $ 48.58 Granted 776,045 $ 82.98 Vested (713,777) $ 65.07 Forfeited (96,159) $ 52.14 Unvested at December 31, 2021 1,079,589 $ 62.09 The aggregate fair value of restricted stock units that vested during the years ended December 31, 2021, 2020 and 2019 was $46 million, $25 million and $45 million, respectively. As of December 31, 2021, the Company’s unrecognized compensation cost related to unvested restricted stock units was $52 million. Such cost is expected to be recognized over a weighted-average period of 2.0 years. During the year ended December 31, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which did not result in any incremental compensation costs. Performance-Based Restricted Stock Units To provide long-term incentives for executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period. In March 2019, eligible employees received performance restricted stock unit awards totaling 199,723 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the performance period of January 1, 2019 to December 31, 2021, subject to continued employment. All remaining awards under this grant cliff vested at December 31, 2021 at 100% based on the final TSR In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards had a performance period of January 1, 2019 to December 31, 2021 and were awarded at 100% based upon the final TSR. The awards under this grant vest in five equal installments beginning on March 1, 2025. 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 based upon the TSR during the three-year performance period of January 1, 2020 to December 31, 2022 and cliff vest at December 31, 2022 subject to continued employment. The initial payout of the March 2020 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%. In March 2021, eligible employees received performance restricted stock unit awards totaling 198,454 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2021 to December 31, 2023 and cliff vest at December 31, 2023 subject to continued employment. The initial payout of the March 2021 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%. 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 awards granted during the period presented: 2021 2020 2019 Grant-date fair value 131.06 $ 70.17 $ 137.22 Grant-date fair value (5-year vesting) $ 132.48 Risk-free rate 0.15 % 0.86 % 2.55 % Company volatility 69.60 % 36.70 % 35.00 % The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2021: Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2020 411,587 $ 99.10 Granted 198,454 $ 131.06 Vested (153,582) $ 137.22 Forfeited — $ — Unvested at December 31, 2021 (1) 456,459 $ 100.17 (1) A maximum of 1,091,711 units could be awarded based upon the Company’s final TSR ranking. As of December 31, 2021, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $26 million, which is expected to be recognized over a weighted-average period of 1.9 years. 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”) which authorized a total of 15.2 million common units for issuance, 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. Excluding unvested common units, as of December 31, 2021, a total of 12,696,146 common units had been reserved for future issuance pursuant to the Rattler LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Rattler LTIP is administered by the board of directors of Rattler’s General Partner or a committee thereof. 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 based on closing price of Rattler’s common units on the grant date of the award, and expenses this value 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 year ended December 31, 2021: Phantom Weighted Average Unvested at December 31, 2020 2,089,668 $ 17.07 Granted 259,916 $ 11.07 Vested (571,341) $ 16.34 Forfeited (40,718) $ 7.28 Unvested at December 31, 2021 1,737,525 $ 16.64 The aggregate fair value of phantom units that vested during the year ended December 31, 2021 was $9 million. As of December 31, 2021, the unrecognized compensation cost related to unvested phantom units was $23 million which is expected to be recognized over a weighted-average period of 2.3 years. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax. The Company and its subsidiaries, other than Viper, Viper LLC, Rattler and Rattler LLC, file a federal corporate income tax return on a consolidated basis. As discussed further below, Viper is a taxable entity for federal income tax purposes effective May 10, 2018, and as such files a federal corporate income tax return including the activity of its investment in Viper LLC. Subsequent to Rattler’s election to be treated as a corporation for federal income tax purposes effective May 24, 2019, Rattler is also a taxable entity and as such files a federal corporate income tax return including the activity of its investment in Rattler LLC. Viper’s and Rattler’s provision for income taxes is included in the Company’s consolidated income tax provision and, to the extent applicable, in net income attributable to the non-controlling interest. The Company’s effective income tax rates were 21.7%, 19.1% and 13.0% for the years ended December 31, 2021, 2020 and 2019, respectively. Total income tax expense for the year ended December 31, 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to state income taxes, net of federal benefit. Total income tax benefit for the year ended December 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to the impact of recording a valuation allowance on Viper’s deferred tax assets, partially offset by state income taxes net of federal benefit and by tax benefit resulting from the carryback of federal net operating losses. Total income tax expense for the year ended December 31, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the impact of deferred taxes recognized as a result of Viper’s change in tax status and state income taxes net of federal benefit. The Company considered the impact of the American Rescue Plan Act, enacted on March 11, 2021, and concluded its provisions related to U.S. income taxes for corporations did not materially affect the Company’s current or deferred tax balances. Under provisions enacted March 27, 2020 in the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), the Company realized income tax benefit of $25 million in the period of enactment related to the carryback of approximately $179 million of the Company’s federal net operating losses to tax years in which the corporate income tax rate was 35%. Prior to the enactment of the 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 assets associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate. As a result of the refund associated with such carryback as well as the accelerated refund available for minimum tax credits, the Company received a refund of federal taxes in the first quarter of 2021 of approximately $100 million. In addition, the Company received in the third quarter of 2021 a federal tax refund of approximately $50 million related to refundable minimum tax credits resulting from carryback of certain federal net operating losses acquired from QEP. The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2021, 2020 and 2019 are as follows: Year Ended December 31, 2021 2020 2019 (In millions) Current income tax provision (benefit): Federal $ 10 $ (62) $ — State 15 — — Total current income tax provision (benefit) 25 (62) — Deferred income tax provision (benefit): Federal 594 (1,010) 40 State 12 (32) 7 Total deferred income tax provision (benefit) 606 (1,042) 47 Total provision for (benefit from) income taxes $ 631 $ (1,104) $ 47 A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows: Year Ended December 31, 2021 2020 2019 (In millions) Income tax expense at the federal statutory rate (21%) $ 610 $ (1,213) $ 76 Income tax benefit relating to net operating loss carryback — (25) — State income tax expense, net of federal tax effect 23 (30) 6 Non-deductible compensation 10 6 4 Change in valuation allowance (12) 153 — Deferred taxes related to change in Viper LP's tax status — — (42) Other, net — 5 3 Provision for (benefit from) income taxes $ 631 $ (1,104) $ 47 The components of the Company’s deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows: December 31, 2021 2020 (In millions) Deferred tax assets: Net operating loss and other carryforwards $ 682 $ 524 Derivative instruments 36 60 Stock based compensation 5 7 Viper's investment in Viper LLC 163 150 Rattler's investment in Rattler LLC 40 58 Other 22 8 Deferred tax assets 948 807 Valuation allowance (315) (166) Deferred tax assets, net of valuation allowance 633 641 Deferred tax liabilities: Oil and natural gas properties and equipment 1,702 1,156 Midstream investments 224 192 Other 5 3 Total deferred tax liabilities 1,931 1,351 Net deferred tax liabilities $ 1,298 $ 710 The Company had net deferred tax liabilities of approximately $1.3 billion and $0.7 billion at December 31, 2021 and 2020, respectively. At December 31, 2021, the Company had approximately $0.5 billion of federal NOLs expiring in 2037 and $2.0 billion of federal NOLs with an indefinite carryforward life, including NOLs acquired from QEP. The Company principally operates in the state of Texas and is subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company’s federal tax attributes, including those acquired from QEP, are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period. Other than as described below regarding realization of tax attributes acquired from QEP, the Company believes that the application of Section 382 will not have an adverse effect on future usage of the Company’s NOLs and credits. On March 17, 2021, the Company completed its acquisition of QEP. For federal income tax purposes, the transaction qualified as a nontaxable merger whereby the Company acquired carryover tax basis in QEP’s assets and liabilities. As of December 31, 2021, QEP’s opening balance sheet net deferred tax asset was approximately $40 million, primarily consisting of deferred tax assets related to tax attributes acquired from QEP, partially offset by a valuation allowance, and deferred tax liabilities resulting from the excess of financial reporting carrying value over tax basis of oil and natural gas properties and other assets acquired from QEP. The acquired income tax attributes, including federal net operating loss and credit carryforwards, are subject to an annual limitation under Section 382. The Company has considered the positive and negative evidence regarding realizability of these federal tax attributes including taxable income in prior carryback years, the annual limitation imposed by Section 382, and the anticipated timing of reversal of its deferred tax liabilities, resulting in a valuation allowance of $23 million on the portion of QEP’s federal tax attributes estimated not more likely than not to be realized prior to expiration. Acquired tax attributes also include state net operating loss carryforwards for which a valuation allowance of $117 million has been provided, since the Company does not believe the state net operating losses are more likely than not to be realized based on its assessment of anticipated future operations in those states. In addition, as of December 31, 2021, the Company had a valuation allowance of $6 million primarily related to certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate future operations in those states and a valuation allowance of $169 million related to Viper’s deferred tax assets, as discussed further below. Management’s assessment at each balance sheet date included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities. Management believes that the balance of the Company’s NOLs are realizable to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. As of December 31, 2021, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets. At December 31, 2021, the Company’s net deferred tax liabilities include deferred tax assets of approximately $6 million related to Viper’s NOL carryforwards and approximately $163 million related to Viper’s investment in Viper LLC. Subsequent to Viper’s change in tax status, deferred taxes are provided on the difference between Viper’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in Viper LLC. As of December 31, 2021, Viper had federal NOL carryforwards of approximately $29 million which may be carried forward indefinitely to offset future taxable income. As of December 31, 2021, Viper had a valuation allowance of approximately $169 million related to deferred tax assets that Viper does not believe are more likely than not to be realized. Management considers the likelihood that Viper’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. 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 as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the assessment resulted in application of a valuation allowance against Viper’s federal deferred tax assets as of March 31, 2020 and subsequent balance sheet dates within the years ended December 31, 2020 and 2021. As discussed further in Note 6— Rattler Midstream LP , 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. At December 31, 2021, the Company’s net deferred tax liabilities include deferred tax assets of approximately $23 million related to Rattlers NOL carryforwards and approximately $40 million related to Rattler’s investment in Rattler LLC. At December 31, 2021, Rattler had federal net operating loss carryforwards of approximately $108 million which may be carried forward indefinitely to offset future taxable income. Management considers the likelihood that Rattler’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. At December 31, 2021, Rattler’s assessment included consideration of all available positive and negative evidence, including Rattler’s projected future taxable income and the anticipated timing of reversal of deferred tax assets. As a result of the assessment, management determined that it is more likely than not that Rattler will realize its deferred tax assets as of December 31, 2021. The following table sets forth changes in the Company’s unrecognized tax benefits: December 31, 2021 2020 (In millions) Balance at beginning of year $ 7 $ 7 Increase resulting from prior period tax positions — — Increase resulting from current period tax positions — — Balance at end of year 7 7 Less: Effects of temporary items (4) (5) Total that, if recognized, would impact the effective income tax rate as of the end of the year $ 3 $ 2 The Company recognizes the tax benefit from a tax position only if it is more likely than not that it will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. The Company’s federal and state income tax returns for 2012 through the current tax year remain open and subject to examination by the IRS and major state taxing jurisdictions. Energen is currently under IRS examination of its federal consolidated income tax returns for 2014 and 2016. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax positions may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVES | DERIVATIVES At December 31, 2021, the Company has commodity derivative contracts and receive-fixed, pay-variable interest rate hedges outstanding. All derivative financial instruments are recorded at fair value. Commodity Contracts The Company has entered into multiple crude oil, natural gas and natural gas liquids derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales. The Company has not designated its commodity derivative instruments as hedges for accounting purposes and, as a result, marks its commodity derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” 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 has entered into commodity derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk. As such, the Company does not require collateral from its counterparties. The Company has multiple commodity derivative contracts that contain an other-than-insignificant financing element at inception and, therefore, the cash receipts were classified as cash flows from financing activities in the consolidated statements of cash flow for the year ended December 31, 2021. As of December 31, 2021, the Company had the following outstanding commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed: Swaps Collars Settlement Month Settlement Year Type of Contract Bbls/MMBtu Per Day Index Weighted Average Differential Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price OIL Jan. - June 2022 Swap 1,000 WTI $— $45.00 $— $— Jan. - June 2022 Swap (1) 13,900 Brent $— $67.54 $— $— Jan. - June 2022 Basis Swap (2) 17,000 Argus WTI Midland $0.66 $— $— $— July - Dec. 2022 Basis Swap (2) 10,000 Argus WTI Midland $0.84 $— $— $— Jan. - Dec. 2022 Roll Swap 30,000 WTI $0.65 $— $— $— Jan. - Mar. 2022 Costless Collar 19,500 WTI $— $— $46.28 $72.67 Jan. - Mar. 2022 Costless Collar 55,000 Brent $— $— $45.55 $71.08 Jan. - Mar. 2022 Costless Collar 22,000 Argus WTI Houston $— $— $45.91 $70.95 Apr. - June 2022 Costless Collar 13,000 WTI $— $— $46.92 $75.00 Apr. - June 2022 Costless Collar 34,000 Brent $— $— $46.47 $77.00 Apr. - June 2022 Costless Collar 26,000 Argus WTI Houston $— $— $46.92 $72.78 July - Sep. 2022 Costless Collar 4,000 WTI $— $— $45.00 $92.65 July - Sep. 2022 Costless Collar 11,000 Brent $— $— $47.73 $78.65 July - Sep. 2022 Costless Collar 10,000 Argus WTI Houston $— $— $50.00 $76.66 Oct. - Dec. 2022 Costless Collar 5,000 Brent $— $— $45.00 $75.56 NATURAL GAS Jan. - Dec. 2022 Basis Swap (2) 230,000 Waha Hub $(0.36) $— $— $— Jan. - Mar. 2022 Costless Collar 350,000 Henry Hub $— $— $2.67 $4.76 Apr. - June 2022 Costless Collar 370,000 Henry Hub $— $— $2.64 $4.89 July - Dec. 2022 Costless Collar 260,000 Henry Hub $— $— $2.67 $5.40 Jan. - June 2023 Basis Swap (2) 60,000 Waha Hub $(0.57) $— $— $— July - Dec. 2023 Basis Swap (2) 40,000 Waha Hub $(0.60) $— $— $— Jan. - Mar. 2023 Costless Collar 80,000 Henry Hub $— $— $2.75 $6.83 Apr. - Dec. 2023 Costless Collar 60,000 Henry Hub $— $— $2.75 $5.72 (1) Excludes 8,250 BO/d of Brent swaptions, whereby the counterparty has the right to exercise the hedge at a weighted-average price of $68.62/Bbl in the second half of 2022. (2) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. Settlement Month Settlement Year Type of Contract Bbls Per Day Index Strike Price Weighted Average Differential Deferred Premium OIL Jan. - Mar. 2022 Put 9,500 WTI $47.51 $— $1.57 Jan. - Mar. 2022 Put 14,000 Brent $50.00 $— $1.66 Jan. - Sep. 2022 Put 8,000 Argus WTI Houston $50.00 $— $1.93 Oct. - Dec. 2022 Put 6,000 Argus WTI Houston $50.00 $— $1.88 Apr. - June 2022 Put 8,000 WTI $47.50 $— $1.55 Apr. - June 2022 Put 24,000 Brent $50.00 $— $1.80 July - Sep. 2022 Put 20,000 Brent $50.00 $— $1.84 Oct. - Dec. 2022 Put 16,000 Brent $50.00 $— $1.84 Jan. - Dec. 2022 Basis Put 50,000 Brent $— $(10.40) $0.78 Interest Rate Swaps In the second quarter of 2021, the Company entered into two interest rate swap agreements for notional amounts of $600 million each to limit the Company’s exposure to changes in the fair value of debt due to movements in LIBOR interest rates. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) whereby the Company will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. Gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt, and were not material for the year ended December 31, 2021. These interest rate swaps are assumed to be perfectly effective and were determined to qualify for the shortcut method of accounting. The swaps expire on December 1, 2029, with an alternative early termination date of September 1, 2029, which mirrors the call option in the 2029 Notes. During 2020 and the first quarter of 2021, the Company used interest rate swaps to reduce its exposure to variable rate interest payments associated with the Company’s revolving credit facility. These interest rate swaps were not designated as hedging instruments and as a result, the Company recognized all changes in fair value immediately in earnings. During the first quarter of 2021, the Company terminated all of its previously outstanding interest rate swaps which resulted in cash received upon settlement of $80 million, net of fees, during the year ended December 31, 2021. The interest rate swaps contained an other-than-insignificant financing element at inception, and therefore, the cash receipts were classified as cash flows from financing activities in the consolidated statements of cash flow for the year ended December 31, 2021. Balance Sheet Offsetting of Derivative Assets and Liabilities The fair value of derivative instruments 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, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 16— Fair Value Measurements for further details. Gains and Losses on Derivative Instruments The following table summarizes the gains and losses on derivative instruments not designated as hedging instruments included in the consolidated statements of operations: Year Ended December 31, 2021 2020 2019 (In millions) Gain (loss) on derivative instruments, net: Commodity contracts $ (978) $ (32) $ (151) Interest rate swaps 130 (49) 43 Total $ (848) $ (81) $ (108) Net cash received (paid) on settlements: Commodity contracts (1)(2) $ (1,305) $ 250 $ 37 Interest rate swaps (3) 80 — 43 Total $ (1,225) $ 250 $ 80 (1) The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million. (2) The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million. (3) The years ended December 31, 2021 and 2019 include cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million and $43 million, respectively. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2021 | |
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. 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 commodity derivative instruments and interest rate swaps. The fair values of the Company’s commodity derivative contracts 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. Interest rate swaps designated as fair value hedges and those that are not designated as hedges are determined based on inputs that are readily available in public markets, can be derived from information available in publicly quoted markets, or are provided by financial institutions that trade these contracts. These valuations are Level 2 inputs. The net fair value of the Company’s interest rate swaps designated as hedges are included in long-term debt in the consolidated balance sheet. The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2021 and December 31, 2020 . The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 60 $ — $ 60 $ (57) $ 3 Interest rate swaps designated as hedges $ — $ 10 $ — $ 10 $ — $ 10 Non-current: Derivative instruments $ — $ 12 $ — $ 12 $ (8) $ 4 Interest rate swaps designated as hedges $ — $ 1 $ — $ 1 $ (1) $ — Liabilities: Current: Derivative instruments $ — $ 231 $ — $ 231 $ (57) $ 174 Non-current: Derivative instruments $ — $ 9 $ — $ 9 $ (8) $ 1 Interest rate swaps designated as hedges $ — $ 29 $ — $ 29 $ (1) $ 28 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 43 $ — $ 43 $ (42) $ 1 Non-current: Derivative instruments $ — $ 187 $ — $ 187 $ (187) $ — Liabilities: Current: Derivative instruments $ — $ 291 $ — $ 291 $ (42) $ 249 Non-current: Derivative instruments $ — $ 244 $ — $ 244 $ (187) $ 57 Assets and Liabilities Not Recorded at Fair Value The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets: December 31, 2021 December 31, 2020 Carrying Carrying Value Fair Value Value Fair Value (In millions) Debt $ 6,687 $ 7,148 $ 5,815 $ 6,213 The fair values of the Company’s credit agreement, the Viper credit agreement and the Rattler credit agreement approximate their carrying values 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 values of the outstanding notes were determined using the December 31, 2021 quoted market prices, a Level 1 classification in the fair value hierarchy. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include those acquired in a business combination, inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. Refer to Note 4— Acquisitions and Divestitures and Note 8— Property and Equipment for additional discussion of nonrecurring fair value adjustments. Fair Value of Financial Assets |
SUPPLEMENTAL INFORMATION TO STA
SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS | 12 Months Ended |
Dec. 31, 2021 | |
Supplemental Cash Flow Information Disclosure [Abstract] | |
SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS | SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS Year Ended December 31, 2021 2020 2019 (In millions) Supplemental disclosure of cash flow information: Interest paid, net of capitalized interest $ 194 $ 221 $ 187 Cash paid (received) for income taxes $ (138) $ — $ — Supplemental disclosure of non-cash transactions: Accrued capital expenditures included in accounts payable and accrued expenses $ 287 $ 213 $ 553 Capitalized stock-based compensation $ 20 $ 16 $ 17 Common stock issued for business combinations $ 1,727 $ — $ — Asset retirement obligations acquired $ 65 $ 2 $ 4 |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2021 | |
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 ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company’s current operations. 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’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. 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. Commitments The following is a schedule of minimum future payments with commitments that have initial or remaining noncancellable terms in excess of one year as of December 31, 2021: Year Ending December 31, Transportation Commitments (1) Sand Supply Agreement (2) Produced Water Disposal Commitments (3) (In millions) 2022 $ 82 $ 18 $ 5 2023 85 18 5 2024 81 18 5 2025 86 18 5 2026 92 5 4 Thereafter 452 — 27 Total $ 878 $ 77 $ 51 (1) The Company has committed to transport gross quantities of crude oil and natural gas on various pipelines under a variety of contracts including throughput and take-or-pay agreements. The Company’s failure to purchase the minimum level of quantities would require it to pay shortfall fees up to the amount of the original monthly commitment amounts included in the table above. (2) The Company has committed to purchase minimum quantities of sand for use in its drilling operations. Our failure to purchase the minimum level of quantities would require us to pay shortfall fees up to the commitment amounts included in the table above. (3) Rattler entered into a minimum volume commitment to purchase produced water disposal services under a 14 year agreement beginning in 2021. At December 31, 2021, the Company’s delivery commitments covered the following gross volumes of oil: Year Ending December 31, Oil Volume Commitments (Bbl/d) 2022 175,000 2023 175,000 2024 125,000 2025 125,000 2026 125,000 Thereafter 325,000 Total 1,050,000 As of December 31, 2021, Rattler’s anticipated future capital commitments for its equity method investments total $28 million in the aggregate. The timing of when capital commitments will be requested can vary, but at December 31, 2021, approximately $11 million of the remaining commitment is expected to be funded in 2022, with the remaining $17 million expected to be funded in 2023. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2021 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENTS Fourth Quarter 2021 Dividend Declaration On February 18, 2022, the Board of Directors of the Company declared a cash dividend for the fourth quarter of 2021 of $0.60 per share of common stock, payable on March 11, 2022 to its stockholders of record at the close of business on March 4, 2022. |
SEGMENT INFORMATION
SEGMENT INFORMATION | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. All of the Company’s equity method investments are included in the midstream operations segment. The segments comprise the structure used by its Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance. The following tables summarize the results of the Company's operating segments during the periods presented: Upstream Midstream Operations Eliminations Total (In millions) Year Ended December 31, 2021: Third-party revenues $ 6,747 $ 50 $ — $ 6,797 Intersegment revenues — 371 (371) — Total revenues $ 6,747 $ 421 $ (371) $ 6,797 Depreciation, depletion, amortization and accretion $ 1,219 $ 56 $ — $ 1,275 Income (loss) from operations $ 3,879 $ 180 $ (58) $ 4,001 Interest expense, net $ (167) $ (32) $ — $ (199) Other income (expense) $ (925) $ 38 $ (8) $ (895) Provision for (benefit from) income taxes $ 620 $ 11 $ — $ 631 Net income (loss) attributable to non-controlling interest $ 57 $ 37 $ — $ 94 Net income (loss) attributable to Diamondback Energy, Inc. $ 2,110 $ 138 $ (66) $ 2,182 Total assets $ 21,329 $ 1,942 $ (373) $ 22,898 Upstream Midstream Operations Eliminations Total (In millions) Year Ended December 31, 2020: Third-party revenues $ 2,756 $ 57 $ — $ 2,813 Intersegment revenues — 367 (367) — Total revenues $ 2,756 $ 424 $ (367) $ 2,813 Depreciation, depletion, amortization and accretion $ 1,257 $ 54 $ — $ 1,311 Impairment of oil and natural gas properties $ 6,021 $ — $ — $ 6,021 Income (loss) from operations $ (5,562) $ 182 $ (96) $ (5,476) Interest expense, net $ (180) $ (17) $ — $ (197) Other income (expense) $ (87) $ (10) $ (6) $ (103) Provision for (benefit from) income taxes $ (1,114) $ 10 $ — $ (1,104) Net income (loss) attributable to non-controlling interest $ (190) $ 35 $ — $ (155) Net income (loss) attributable to Diamondback Energy, Inc. $ (4,525) $ 110 $ (102) $ (4,517) Total assets $ 16,128 $ 1,809 $ (318) $ 17,619 Upstream Midstream Operations Eliminations Total (In millions) Year Ended December 31, 2019: Third-party revenues $ 3,891 $ 73 $ — $ 3,964 Intersegment revenues — 375 (375) — Total revenues $ 3,891 $ 448 $ (375) $ 3,964 Depreciation, depletion, amortization and accretion $ 1,411 $ 43 $ — $ 1,454 Impairment of oil and natural gas properties $ 790 $ — $ — $ 790 Income (loss) from operations $ 790 $ 219 $ (314) $ 695 Interest expense, net $ (171) $ (1) $ — $ (172) Other income (expense) $ (149) $ (6) $ (6) $ (161) Provision for (benefit from) income taxes $ 21 $ 26 $ — $ 47 Net income (loss) attributable to non-controlling interest $ 75 $ 91 $ (91) $ 75 Net income (loss) attributable to Diamondback Energy, Inc. $ 374 $ 95 $ (229) $ 240 Total assets $ 22,125 $ 1,636 $ (230) $ 23,531 |
SUPPLEMENTAL INFORMATION ON OIL
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) | 12 Months Ended |
Dec. 31, 2021 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) | SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) The Company’s oil and natural gas reserves are attributable solely to properties within the United States. Capitalized oil and natural gas costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: December 31, 2021 2020 (In millions) Oil and natural gas properties: Proved properties $ 24,418 $ 19,884 Unproved properties 8,496 7,493 Total oil and natural gas properties 32,914 27,377 Accumulated depletion (5,434) (4,237) Accumulated impairment (7,954) (7,954) Net oil and natural gas properties capitalized $ 19,526 $ 15,186 Costs incurred in oil and natural gas activities Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows: Year Ended December 31, 2021 2020 2019 (In millions) Acquisition costs: Proved properties $ 2,805 $ 13 $ 194 Unproved properties 1,829 106 418 Development costs 516 381 956 Exploration costs 1,223 1,098 1,915 Total $ 6,373 $ 1,598 $ 3,483 Results of Operations from Oil and Natural Gas Producing Activities The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and income tax expense has been calculated by applying statutory income tax rates to oil, gas and natural gas liquids sales after deducting production costs, depreciation, depletion and amortization and accretion and impairment. Therefore, the following schedule is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations. Year Ended December 31, 2021 2020 2019 (In millions) Oil, natural gas and natural gas liquid sales $ 6,747 $ 2,756 $ 3,887 Production costs (1,202) (760) (826) Depreciation, depletion, amortization and accretion (1,211) (1,249) (1,405) Impairment — (6,021) (790) Income tax benefit (expense) (918) 1,151 (186) Results of operations $ 3,416 $ (4,123) $ 680 Oil and Natural Gas Reserves Proved oil and natural gas reserve estimates as of December 31, 2021, 2020 and 2019 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The changes in estimated proved reserves are as follows: Oil Natural Gas Natural Gas Proved Developed and Undeveloped Reserves: As of December 31, 2018 626,936 190,291 1,048,649 Extensions and discoveries 256,569 66,572 318,874 Revisions of previous estimates (84,789) (8,166) (149,657) Purchase of reserves in place 13,974 3,813 19,830 Divestitures (33,269) (3,809) (21,272) Production (68,518) (18,498) (97,613) As of December 31, 2019 710,903 230,203 1,118,811 Extensions and discoveries 191,009 58,410 316,035 Revisions of previous estimates (78,244) 21,927 300,160 Purchase of reserves in place 2,124 778 3,512 Divestitures (209) (141) (905) Production (66,182) (21,981) (130,549) As of December 31, 2020 759,401 289,196 1,607,064 Extensions and discoveries 271,222 127,479 720,125 Revisions of previous estimates (160,570) (6,685) 195,302 Purchase of reserves in place 176,261 58,587 302,770 Divestitures (36,503) (11,597) (70,048) Production (81,522) (27,246) (169,406) As of December 31, 2021 928,289 429,734 2,585,807 Proved Developed Reserves: December 31, 2018 403,051 125,509 705,084 December 31, 2019 457,083 165,173 824,760 December 31, 2020 443,464 192,495 1,085,035 December 31, 2021 620,474 285,513 1,770,688 Proved Undeveloped Reserves: December 31, 2018 223,885 64,782 343,565 December 31, 2019 253,820 65,030 294,051 December 31, 2020 315,937 96,701 522,029 December 31, 2021 307,815 144,221 815,119 Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. During the year ended December 31, 2021, the Company’s extensions and discoveries of 518,722 MBOE resulted primarily from the drilling of 470 new wells, including 345 wells in which we own only a mineral interest through Viper, and from 439 new proved undeveloped locations added. Viper royalty interests accounted for 6% of the extension volumes. The Company’s downward revisions of previous estimates of 134,705 MBOE were the result of negative revisions of 268,560 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 133,855 MBOE associated with higher commodity prices and improved well performance. Purchases of 285,309 MBOE primarily resulted from 276,207 MBOE attributable largely to the QEP Merger and Guidon Acquisition, and 9,102 MBOE of Viper royalty purchases, including the Swallowtail Acquisition. Divestitures of 59,775 MBOE related primarily to the Williston Basin Divestiture. During the year ended December 31, 2020, the Company’s extensions and discoveries of 302,092 MBOE resulted primarily from the drilling of 682 new wells and from 298 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s downward revisions of previous estimates of 6,290 MBOE were the result of negative revisions due to lower product pricing of 54,645 MBOE, which were partially offset by positive revisions of 23,066 MBOE associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 31,579 MBOE. Downgrades of 31,074 MBOE are primarily from changes in the corporate development plan. These revisions were offset by positive performance revisions of 56,362 MBOE associated with less gas flaring and a corresponding increase in natural gas liquid recoveries. During the year ended December 31, 2019, the Company’s extensions and discoveries totaling 376,287 MBOE resulted primarily from the drilling of 283 new wells and from 291 new proved undeveloped locations added. Viper royalty interests accounted for 5% of the extension volumes. The Company’s downward revisions of 117,898 MBOE were the result of proved undeveloped downgrades associated with inventory refinement following the Energen acquisition along with updated development plans and lower realized prices. Purchases of 21,092 MBOE were the result of 10,939 MBOE of working interest purchases and 10,153 MBOE of Viper royalty purchases, excluding mineral interests dropped down to Viper. At December 31, 2021, the Company’s estimated PUD reserves were approximately 587,889 MBOE, an 88,246 MBOE increase over the reserve estimate at December 31, 2020 of 499,643 MBOE. The following table includes the changes in PUD reserves for 2021 (MBOE): Beginning proved undeveloped reserves at December 31, 2020 499,643 Undeveloped reserves transferred to developed (172,526) Revisions (243,268) Purchases 63,013 Divestitures — Extensions and discoveries 441,027 Ending proved undeveloped reserves at December 31, 2021 587,889 The increase in proved undeveloped reserves was primarily attributable to extensions of 416,327 MBOE from 439 gross (383 net) wells in which the Company has a working interest and 24,700 MBOE from 336 gross wells in which Viper owns royalty interests. Of the 439 gross working interest wells, 409 were in the Midland Basin and 30 were in the Delaware Basin. Transfers of 172,526 MBOE from undeveloped to developed reserves were the result of drilling or participating in 154 gross (142 net) horizontal wells in which the Company has a working interest and 127 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 106 of the 127 gross Viper wells. Downward revisions of 243,268 MBOE were the result of negative revisions of 260,494 MBOE due to downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 17,226 MBOE primarily attributable to higher commodity prices and improved well performance. Purchases of 63,013 MBOE were the result of 59,023 MBOE primarily from QEP and Guidon, and 3,990 MBOE of Viper royalty purchases. As of December 31, 2021, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2021, approximately $516 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells. Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows is based on the unweighted arithmetic average, first-day-of-the-month price for the rolling 12-month period. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2021, 2020 and 2019: December 31, 2021 2020 2019 (In millions) Future cash inflows $ 77,085 $ 32,173 $ 40,681 Future development costs (4,243) (3,585) (3,809) Future production costs (19,123) (10,763) (9,319) Future production taxes (5,572) (2,354) (2,905) Future income tax expenses (7,237) (727) (2,635) Future net cash flows 40,910 14,744 22,013 10% discount to reflect timing of cash flows (22,193) (7,986) (11,829) Standardized measure of discounted future net cash flows (1) $ 18,717 $ 6,758 $ 10,184 (1) Includes $2.1 billion, $1.0 billion, and $1.3 billion, for the years ended December 31, 2021, 2020 and 2019, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 54% non-controlling interest at December 31, 2021. The table below presents the unweighted arithmetic average first-day-of–the-month price for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows: December 31, 2021 2020 2019 Oil (per Bbl) $ 64.78 $ 38.06 $ 51.88 Natural gas (per Mcf) $ 2.61 $ 0.09 $ 0.18 Natural gas liquids (per Bbl) $ 23.71 $ 10.83 $ 15.65 Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: Year Ended December 31, 2021 2020 2019 (In millions) Standardized measure of discounted future net cash flows at the beginning of the period $ 6,758 $ 10,184 $ 11,676 Sales of oil and natural gas, net of production costs (5,757) (2,225) (3,334) Acquisitions of reserves 1,914 30 309 Divestitures of reserves (275) (4) (500) Extensions and discoveries, net of future development costs 6,298 1,514 4,004 Previously estimated development costs incurred during the period 548 704 120 Net changes in prices and production costs 10,748 (5,273) 831 Changes in estimated future development costs (19) 526 (3,190) Revisions of previous quantity estimates 719 (462) (1,242) Accretion of discount 703 1,126 1,344 Net change in income taxes (2,841) 807 693 Net changes in timing of production and other (79) (169) (527) Standardized measure of discounted future net cash flows at the end of the period $ 18,717 $ 6,758 $ 10,184 |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
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. Diamondback’s publicly traded subsidiaries Viper and Rattler are consolidated in the financial statements of the Company. As of December 31, 2021, the Company owned approximately 54% of Viper’s total units outstanding. The Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. As of December 31, 2021, the Company owned approximately 74% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the equity and net income attributable to the Company. The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows. |
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 as of the date of the consolidated financial statements. Actual results could differ from those estimates. Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices and the effects of the ongoing COVID-19 pandemic. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts. |
Cash and Cash Equivalents and Restricted Cash | Cash, Cash Equivalents and Restricted CashThe Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. |
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 |
Derivative Instruments | Derivative InstrumentsThe Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. For commodity derivative instruments and interest rate swaps which have not been designated as hedges for accounting purposes, the Company marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. The Company accounts for its interest rate swaps which have been designated as fair value hedges under the “shortcut” method of accounting. As such, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties 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. 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 and natural liquids. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $8.77, $11.30 and $13.54 for the years ended December 31, 2021, 2020 and 2019, respectively. Depletion expense for oil and natural gas properties was $1.2 billion, $1.2 billion and $1.4 billion for the years ended December 31, 2021, 2020 and 2019, respectively. Under this 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 revenues, 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, 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 write-down is required. For additional information regarding the Company’s impairments on proved oil and natural gas properties, see Note 8— Property and Equipment . 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 Company assesses all items classified as unevaluated property on at least an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. |
Real Estate Assets | Real Estate Assets Real estate assets are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life. |
Other Property and Equipment | Other Property, Equipment and Land Other property, equipment and land is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight-line method over their estimated useful lives, which range from three |
Asset Retirement Obligations | Asset Retirement Obligations The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties. |
Impairment or Long-Lived Assets | Impairment of Long-Lived Assets Other property and equipment used in operations and midstream assets are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. |
Capitalized Interest | Capitalized InterestThe Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. |
Inventories | Inventories Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2021 and 2020. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. |
Debt Issuance Costs | Debt Issuance Costs Long-term debt includes capitalized costs related to the senior notes, net of accumulated amortization. The costs associated with the senior notes are netted against the senior notes balances and are amortized over the term of the senior notes using the effective interest method. See Note 11— Debt for further details. The costs associated with the Company’s credit facilities are included in other assets on the consolidated balance sheet and are amortized over the term of the facility. |
Revenue and Royalties Payable | Revenue and Royalties PayableFor certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties. |
Non-controlling Interest | Non-controlling InterestsNon-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, “Consolidation”, which requires that any differences between the carrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. |
Revenue Recognition | Revenue Recognition Revenue from Contracts with Customers Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. Oil sales The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations. Natural gas and natural gas liquids sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. Generally, 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 water volumes have been delivered to the frac-water 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 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. 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. 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. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for 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 |
Investments | Investments The Company accounts for its corporate joint ventures under the equity method of accounting in accordance with Financial Accounting Standards Board Accounting Standards Codification (“ASC”) Topic 323 “Investments — Equity Method and Joint Ventures.” The Company also applies the equity method of accounting to investments of less than 50% in an investee over which the Company exercises significant influence but does not have control and investments of greater than 50% in an investee over which the Company does not exercise significant influence or have control. Under the equity method, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statement of operations. As of December 31, 2021, the Company’s proportionate share of the income or loss from equity method investments is recognized on a one-month lag for all equity method investments. Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method. |
Accounting for Stock-based Compensation | Accounting for Equity-Based Compensation The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper and Rattler have granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner, Rattler’s General Partner and the Company who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 13— Equity-Based Compensation . Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period. Forfeitures for these awards are recognized as they occur. |
Environmental Compliance and Remediation | Environmental Compliance and Remediation Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated. |
Income Taxes | Income Taxes The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Recently Adopted Pronouncements In December 2019, the FASB issued 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 and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022 with early adoption permitted. The Company continues to evaluate the provisions of this update, but does not believe the adoption will have a material impact on its financial position, results of operations or liquidity. |
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. |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Schedule of Other Accrued Liabilities | Other accrued liabilities consist of the following: December 31, 2021 2020 (In millions) Derivative liability payable $ 101 $ 30 Lease operating expenses payable 86 115 Ad valorem taxes payable 70 57 Accrued compensation 48 27 Interest payable 46 37 Midstream operating expenses payable 13 18 Liability for drilling costs prepaid by joint interest partners 10 5 Other 62 13 Total other accrued liabilities $ 436 $ 302 |
REVENUE FROM CONTRACTS WITH C_2
REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin: Year Ended December 31, 2021 Midland Basin Delaware Basin Other Total (In millions) Oil sales $ 3,468 $ 1,663 $ 265 $ 5,396 Natural gas sales 327 215 27 569 Natural gas liquid sales 493 249 40 782 Total $ 4,288 $ 2,127 $ 332 $ 6,747 Year Ended December 31, 2020 Midland Basin Delaware Basin Other Total (In millions) Oil sales $ 1,393 $ 1,011 $ 6 $ 2,410 Natural gas sales 56 50 1 107 Natural gas liquid sales 138 100 1 239 Total $ 1,587 $ 1,161 $ 8 $ 2,756 Three Months Ended December 31, 2019 Midland Basin Delaware Basin Other Total (In millions) Oil sales $ 2,139 $ 1,351 $ 64 $ 3,554 Natural gas sales 32 33 1 66 Natural gas liquid sales 154 110 3 267 Total $ 2,325 $ 1,494 $ 68 $ 3,887 |
ACQUISITIONS AND DIVESTITURES (
ACQUISITIONS AND DIVESTITURES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Business Combinations And Divestitures [Abstract] | |
Schedule of Asset Acquisition | The following table presents the acquisition consideration paid in the Guidon Acquisition (in millions, except per share data, shares in thousands): Consideration: Shares of Diamondback common stock issued at closing 10,676 Closing price per share of Diamondback common stock on the closing date $ 69.28 Fair value of Diamondback common stock issued $ 740 Cash consideration 375 Total consideration (including fair value of Diamondback common stock issued) $ 1,115 The following table sets forth the Company’s preliminary purchase price allocation (in millions): Total consideration $ 1,115 Fair value of liabilities assumed: Asset retirement obligations 9 Fair value of assets acquired: Oil and gas properties 1,110 Midstream assets 14 Amount attributable to assets acquired 1,124 Net assets acquired and liabilities assumed $ 1,115 |
Schedule of Acquisition Consideration Paid | The following table presents the acquisition consideration paid to QEP stockholders in the QEP Merger (in millions, except per share data, shares in thousands): Consideration: Eligible shares of QEP common stock converted into shares of Diamondback common stock 238,153 Shares of QEP equity awards included in precombination consideration 4,221 Total shares of QEP common stock eligible for merger consideration 242,374 Exchange ratio 0.050 Shares of Diamondback common stock issued as merger consideration 12,119 Closing price per share of Diamondback common stock $ 81.41 Total consideration (fair value of the Company's common stock issued) $ 987 |
Schedule of Estimated Fair Values of Assets Acquired and Liabilities Assumed | The following table sets forth the Company’s preliminary purchase price allocation (in millions): Total consideration $ 987 Fair value of liabilities assumed: Accounts payable - trade $ 26 Accrued capital expenditures 38 Other accrued liabilities 107 Revenues and royalties payable 67 Derivative instruments 242 Long-term debt 1,710 Asset retirement obligations 54 Other long-term liabilities 63 Amount attributable to liabilities assumed $ 2,307 Fair value of assets acquired: Cash, cash equivalents and restricted cash $ 22 Accounts receivable - joint interest and other, net 87 Accounts receivable - oil and natural gas sales, net 44 Inventories 18 Income tax receivable 33 Prepaid expenses and other current assets 7 Oil and natural gas properties 2,927 Other property, equipment and land 10 Deferred income taxes 40 Other assets 106 Amount attributable to assets acquired 3,294 Net assets acquired and liabilities assumed $ 987 |
Schedule of Business Acquisition Pro Forma | The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. Year Ended December 31, 2021 2020 (In millions, except per share amounts) Revenues $ 7,069 $ 3,727 Income (loss) from operations $ 4,182 $ (5,771) Net income (loss) $ 2,186 $ (4,641) Basic earnings per common share $ 12.09 $ (25.67) Diluted earnings per common share $ 12.05 $ (25.67) |
REAL ESTATE ASSETS (Tables)
REAL ESTATE ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Real Estate [Abstract] | |
Schedule of Real Estate Assets | The following schedules present the cost and related accumulated depreciation related to Diamondback’s significant real estate assets: Estimated Useful Lives December 31, 2021 2020 (Years) (In millions) Buildings 20-30 $ 95 $ 102 Tenant improvements 5 - 15 4 5 Land N/A 1 2 Land improvements 5 - 15 1 1 Total real estate assets 101 110 Less: accumulated depreciation (16) (13) Total investment in land and buildings, net $ 85 $ 97 |
PROPERTY AND EQUIPMENT (Tables)
PROPERTY AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Property and Equipment | Property and equipment includes the following: December 31, 2021 2020 (In millions) Oil and natural gas properties: Subject to depletion $ 24,418 $ 19,884 Not subject to depletion 8,496 7,493 Gross oil and natural gas properties 32,914 27,377 Accumulated depletion (5,434) (4,237) Accumulated impairment (7,954) (7,954) Oil and natural gas properties, net 19,526 15,186 Midstream assets 1,076 1,013 Other property, equipment and land 174 138 Accumulated depreciation and impairment (157) (123) Total property and equipment, net $ 20,619 $ 16,214 Balance of costs not subject to depletion: Incurred in 2021 $ 1,688 Incurred in 2020 71 Incurred in 2019 422 Thereafter 6,315 Total not subject to depletion $ 8,496 |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Asset Retirement Obligations | The following table describes the changes to the Company’s asset retirement obligations liability for the following periods: Year Ended December 31, 2021 2020 (In millions) Asset retirement obligations, beginning of period $ 109 $ 94 Additional liabilities incurred 11 13 Liabilities acquired 65 2 Liabilities settled and divested (36) (8) Accretion expense 9 7 Revisions in estimated liabilities 13 1 Asset retirement obligations, end of period 171 109 Less: current portion (1) 5 1 Asset retirement obligations - long-term $ 166 $ 108 (1) The current portion of the asset retirement obligation is included in other accrued liabilities in the Company’s consolidated balance sheets. |
EQUITY METHOD INVESTMENTS (Tabl
EQUITY METHOD INVESTMENTS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | At December 31, 2021 and 2020, Rattler had the following investments: Ownership Interest December 31, 2021 December 31, 2020 (In millions) EPIC Crude Holdings, LP 10 % $ 107 $ 121 Gray Oak Pipeline, LLC 10 % 121 130 Wink to Webster Pipeline LLC (1) 4 % 86 83 OMOG JV LLC 60 % 188 194 Amarillo Rattler, LLC (2) — % — 5 Remuda Midstream Holdings LLC 25 % 111 — Total $ 613 $ 533 (1) The Wink to Webster joint venture is developing a crude oil pipeline (the “Wink to Webster pipeline”). The Wink to Webster pipeline’s main segment began interim service operation in the fourth quarter of 2020, and the joint venture is expected to begin full commercial operations in the first quarter of 2022. (2) The ownership interest in Amarillo Rattler was 50% at December 31, 2020. See Note 4— Acquisitions and D ivestitures for discussion regarding the sale of this equity method investment during the second quarter of 2021. |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt | The Company’s debt consisted of the following as of the dates indicated: December 31, 2021 2020 (In millions) 4.625% Notes due 2021 (1) $ — $ 191 5.375% Senior Notes due 2022 (3) 25 — 7.320% Medium-term Notes, Series A, due 2022 (4) 20 20 5.250% Senior Notes due 2023 (3) 10 — 2.875% Senior Notes due 2024 1,000 1,000 4.750% Senior Notes due 2025 500 500 5.375% Senior Notes due 2025 (2) — 800 3.250% Senior Notes due 2026 800 800 5.625% Senior Notes due 2026 (3) 14 — 7.125% Medium-term Notes, Series B, due 2028 (4) 100 100 3.500% Senior Notes due 2029 1,200 1,200 3.125% Senior Notes due 2031 900 — 4.400% Senior Notes due 2051 650 — DrillCo Agreement (5) 58 79 Unamortized debt issuance costs (31) (29) Unamortized discount costs (28) (27) Unamortized premium costs 8 15 Fair value of interest rate swap agreements (6) (18) — Revolving credit facility — 23 Viper revolving credit facility 304 84 Viper 5.375% Senior Notes due 2027 480 480 Rattler revolving credit facility 195 79 Rattler 5.625% Senior Notes due 2025 500 500 Total debt, net 6,687 5,815 Less: current maturities of long-term debt (45) (191) Total long-term debt $ 6,642 $ 5,624 (1) In June 2021, the Company redeemed the remaining $191 million principal amount of outstanding legacy 4.625% senior notes due September 1, 2021 of Energen. (2) In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes. (3) At the effective time of the QEP Merger, QEP became a wholly owned subsidiary of the Company and remained the issuer of these senior notes. (4) In November 2018, Energen became the Company’s wholly owned subsidiary and remained the issuer of these senior notes. In connection with the E&P Merger, Diamondback E&P became the successor issuer under the indenture. (5) The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. As of December 31, 2021, the amount due to CEMOF related to this alliance was $58 million. As of December 31, 2021, fifteen joint wells under this agreement have been drilled and completed. (6) The Company has two interest rate swap agreements in place on the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. See Note 15— Derivatives for additional information on the Company’s interest rate swaps designated as fair value hedges. |
Schedule of Maturities of Long-term Debt | Debt maturities as of December 31, 2021, excluding debt issuance costs, premiums and discounts and fair value of interest rate swap premiums are as follows: Year Ending December 31, (In millions) 2022 $ 45 2023 10 2024 1,195 2025 1,304 2026 814 Thereafter 3,388 Total $ 6,756 |
Schedule of Financial Covenants | 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 in the Viper credit agreement Not less than 1.0 to 1.0 Ratio of secured debt to EBITDAX, as defined in the Viper credit agreement Not greater than 2.5 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 Financial Covenant Election (as defined in the Rattler credit agreement) is made, 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 |
Schedule of Interest Expense | The following amounts have been incurred and charged to interest expense for the years ended December 31, 2021, 2020 and 2019: Year Ended December 31, 2021 2020 2019 (In millions) Interest expense $ 277 $ 250 $ 235 Other fees and expenses 11 6 4 Less: interest income 1 4 1 Less: capitalized interest 88 55 66 Interest expense, net $ 199 $ 197 $ 172 |
STOCKHOLDERS_ EQUITY AND EARN_2
STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
Schedule of Change in Ownership of Consolidated Subsidiaries | The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period: Year Ended December 31, 2021 2020 2019 (In millions) Net income (loss) attributable to the Company $ 2,182 $ (4,517) $ 240 Change in ownership of consolidated subsidiaries (1) 66 358 (33) Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest $ 2,248 $ (4,159) $ 207 (1) The year ended December 31, 2020 includes an adjustment to non-controlling interest for Rattler of $329 million and to additional paid-in-capital of $329 million to reflect the ownership structure that was effective at June 30, 2020. The adjustment had no impact on the consolidated statement of income or consolidated statement of cash flows for the year ended December 31, 2020. |
Schedule of Reconciliation of Basic and Diluted Net Income per Share | A reconciliation of the components of basic and diluted earnings (loss) per common share is presented in the table below: Year Ended December 31, 2021 2020 2019 (In millions, except per share amounts, shares in thousands) Net income (loss) attributable to common stock $ 2,182 $ (4,517) $ 240 Weighted average common shares outstanding: Basic weighted average common shares outstanding 176,643 157,976 163,493 Effect of dilutive securities: Potential common shares issuable (1)(2) 716 — 350 Diluted weighted average common shares outstanding 177,359 157,976 163,843 Basic net income (loss) attributable to common stock $ 12.35 $ (28.59) $ 1.47 Diluted net income (loss) attributable to common stock $ 12.30 $ (28.59) $ 1.47 (1) For the year ended December 31, 2021, there were 115,865 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method. |
EQUITY-BASED COMPENSATION (Tabl
EQUITY-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
Schedule of Stock-based Compensation Plans and Related Costs | The following table presents the effects of the equity and stock based compensation plans and related costs: Year Ended December 31, 2021 2020 2019 (In millions) General and administrative expenses $ 51 $ 37 $ 48 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties $ 20 $ 16 $ 17 |
Schedule of Restricted Stock Units | The following table presents the Company’s restricted stock unit activity under the Equity Plan during the year ended December 31, 2021: Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2020 1,113,480 $ 48.58 Granted 776,045 $ 82.98 Vested (713,777) $ 65.07 Forfeited (96,159) $ 52.14 Unvested at December 31, 2021 1,079,589 $ 62.09 |
Schedule 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 awards granted during the period presented: 2021 2020 2019 Grant-date fair value 131.06 $ 70.17 $ 137.22 Grant-date fair value (5-year vesting) $ 132.48 Risk-free rate 0.15 % 0.86 % 2.55 % Company volatility 69.60 % 36.70 % 35.00 % |
Schedule of Performance Restricted Stock Units Activity | The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2021: Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2020 411,587 $ 99.10 Granted 198,454 $ 131.06 Vested (153,582) $ 137.22 Forfeited — $ — Unvested at December 31, 2021 (1) 456,459 $ 100.17 (1) A maximum of 1,091,711 units could be awarded based upon the Company’s final TSR ranking. |
Schedule of Phantom Units Activity | The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2021: Phantom Weighted Average Unvested at December 31, 2020 2,089,668 $ 17.07 Granted 259,916 $ 11.07 Vested (571,341) $ 16.34 Forfeited (40,718) $ 7.28 Unvested at December 31, 2021 1,737,525 $ 16.64 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Provision (Benefit) | The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2021, 2020 and 2019 are as follows: Year Ended December 31, 2021 2020 2019 (In millions) Current income tax provision (benefit): Federal $ 10 $ (62) $ — State 15 — — Total current income tax provision (benefit) 25 (62) — Deferred income tax provision (benefit): Federal 594 (1,010) 40 State 12 (32) 7 Total deferred income tax provision (benefit) 606 (1,042) 47 Total provision for (benefit from) income taxes $ 631 $ (1,104) $ 47 |
Schedule of Reconciliation of Statutory Federal Income Tax | A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows: Year Ended December 31, 2021 2020 2019 (In millions) Income tax expense at the federal statutory rate (21%) $ 610 $ (1,213) $ 76 Income tax benefit relating to net operating loss carryback — (25) — State income tax expense, net of federal tax effect 23 (30) 6 Non-deductible compensation 10 6 4 Change in valuation allowance (12) 153 — Deferred taxes related to change in Viper LP's tax status — — (42) Other, net — 5 3 Provision for (benefit from) income taxes $ 631 $ (1,104) $ 47 |
Schedule of Deferred Tax Assets and Liabilities | The components of the Company’s deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows: December 31, 2021 2020 (In millions) Deferred tax assets: Net operating loss and other carryforwards $ 682 $ 524 Derivative instruments 36 60 Stock based compensation 5 7 Viper's investment in Viper LLC 163 150 Rattler's investment in Rattler LLC 40 58 Other 22 8 Deferred tax assets 948 807 Valuation allowance (315) (166) Deferred tax assets, net of valuation allowance 633 641 Deferred tax liabilities: Oil and natural gas properties and equipment 1,702 1,156 Midstream investments 224 192 Other 5 3 Total deferred tax liabilities 1,931 1,351 Net deferred tax liabilities $ 1,298 $ 710 |
Schedule of Unrecognized Tax Benefits | The following table sets forth changes in the Company’s unrecognized tax benefits: December 31, 2021 2020 (In millions) Balance at beginning of year $ 7 $ 7 Increase resulting from prior period tax positions — — Increase resulting from current period tax positions — — Balance at end of year 7 7 Less: Effects of temporary items (4) (5) Total that, if recognized, would impact the effective income tax rate as of the end of the year $ 3 $ 2 |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments | As of December 31, 2021, the Company had the following outstanding commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed: Swaps Collars Settlement Month Settlement Year Type of Contract Bbls/MMBtu Per Day Index Weighted Average Differential Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price OIL Jan. - June 2022 Swap 1,000 WTI $— $45.00 $— $— Jan. - June 2022 Swap (1) 13,900 Brent $— $67.54 $— $— Jan. - June 2022 Basis Swap (2) 17,000 Argus WTI Midland $0.66 $— $— $— July - Dec. 2022 Basis Swap (2) 10,000 Argus WTI Midland $0.84 $— $— $— Jan. - Dec. 2022 Roll Swap 30,000 WTI $0.65 $— $— $— Jan. - Mar. 2022 Costless Collar 19,500 WTI $— $— $46.28 $72.67 Jan. - Mar. 2022 Costless Collar 55,000 Brent $— $— $45.55 $71.08 Jan. - Mar. 2022 Costless Collar 22,000 Argus WTI Houston $— $— $45.91 $70.95 Apr. - June 2022 Costless Collar 13,000 WTI $— $— $46.92 $75.00 Apr. - June 2022 Costless Collar 34,000 Brent $— $— $46.47 $77.00 Apr. - June 2022 Costless Collar 26,000 Argus WTI Houston $— $— $46.92 $72.78 July - Sep. 2022 Costless Collar 4,000 WTI $— $— $45.00 $92.65 July - Sep. 2022 Costless Collar 11,000 Brent $— $— $47.73 $78.65 July - Sep. 2022 Costless Collar 10,000 Argus WTI Houston $— $— $50.00 $76.66 Oct. - Dec. 2022 Costless Collar 5,000 Brent $— $— $45.00 $75.56 NATURAL GAS Jan. - Dec. 2022 Basis Swap (2) 230,000 Waha Hub $(0.36) $— $— $— Jan. - Mar. 2022 Costless Collar 350,000 Henry Hub $— $— $2.67 $4.76 Apr. - June 2022 Costless Collar 370,000 Henry Hub $— $— $2.64 $4.89 July - Dec. 2022 Costless Collar 260,000 Henry Hub $— $— $2.67 $5.40 Jan. - June 2023 Basis Swap (2) 60,000 Waha Hub $(0.57) $— $— $— July - Dec. 2023 Basis Swap (2) 40,000 Waha Hub $(0.60) $— $— $— Jan. - Mar. 2023 Costless Collar 80,000 Henry Hub $— $— $2.75 $6.83 Apr. - Dec. 2023 Costless Collar 60,000 Henry Hub $— $— $2.75 $5.72 (1) Excludes 8,250 BO/d of Brent swaptions, whereby the counterparty has the right to exercise the hedge at a weighted-average price of $68.62/Bbl in the second half of 2022. (2) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. Settlement Month Settlement Year Type of Contract Bbls Per Day Index Strike Price Weighted Average Differential Deferred Premium OIL Jan. - Mar. 2022 Put 9,500 WTI $47.51 $— $1.57 Jan. - Mar. 2022 Put 14,000 Brent $50.00 $— $1.66 Jan. - Sep. 2022 Put 8,000 Argus WTI Houston $50.00 $— $1.93 Oct. - Dec. 2022 Put 6,000 Argus WTI Houston $50.00 $— $1.88 Apr. - June 2022 Put 8,000 WTI $47.50 $— $1.55 Apr. - June 2022 Put 24,000 Brent $50.00 $— $1.80 July - Sep. 2022 Put 20,000 Brent $50.00 $— $1.84 Oct. - Dec. 2022 Put 16,000 Brent $50.00 $— $1.84 Jan. - Dec. 2022 Basis Put 50,000 Brent $— $(10.40) $0.78 |
Schedule of Derivative Contract Gains and Losses Included in the Consolidated Statements of Operations | The following table summarizes the gains and losses on derivative instruments not designated as hedging instruments included in the consolidated statements of operations: Year Ended December 31, 2021 2020 2019 (In millions) Gain (loss) on derivative instruments, net: Commodity contracts $ (978) $ (32) $ (151) Interest rate swaps 130 (49) 43 Total $ (848) $ (81) $ (108) Net cash received (paid) on settlements: Commodity contracts (1)(2) $ (1,305) $ 250 $ 37 Interest rate swaps (3) 80 — 43 Total $ (1,225) $ 250 $ 80 (1) The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million. (2) The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million. (3) The years ended December 31, 2021 and 2019 include cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million and $43 million, respectively. |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value Measurement Information For Financial Instruments Measured on a Recurring Basis | The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2021 and December 31, 2020 . The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 60 $ — $ 60 $ (57) $ 3 Interest rate swaps designated as hedges $ — $ 10 $ — $ 10 $ — $ 10 Non-current: Derivative instruments $ — $ 12 $ — $ 12 $ (8) $ 4 Interest rate swaps designated as hedges $ — $ 1 $ — $ 1 $ (1) $ — Liabilities: Current: Derivative instruments $ — $ 231 $ — $ 231 $ (57) $ 174 Non-current: Derivative instruments $ — $ 9 $ — $ 9 $ (8) $ 1 Interest rate swaps designated as hedges $ — $ 29 $ — $ 29 $ (1) $ 28 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 43 $ — $ 43 $ (42) $ 1 Non-current: Derivative instruments $ — $ 187 $ — $ 187 $ (187) $ — Liabilities: Current: Derivative instruments $ — $ 291 $ — $ 291 $ (42) $ 249 Non-current: Derivative instruments $ — $ 244 $ — $ 244 $ (187) $ 57 |
Schedule of Offsetting Assets | The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2021 and December 31, 2020 . The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 60 $ — $ 60 $ (57) $ 3 Interest rate swaps designated as hedges $ — $ 10 $ — $ 10 $ — $ 10 Non-current: Derivative instruments $ — $ 12 $ — $ 12 $ (8) $ 4 Interest rate swaps designated as hedges $ — $ 1 $ — $ 1 $ (1) $ — Liabilities: Current: Derivative instruments $ — $ 231 $ — $ 231 $ (57) $ 174 Non-current: Derivative instruments $ — $ 9 $ — $ 9 $ (8) $ 1 Interest rate swaps designated as hedges $ — $ 29 $ — $ 29 $ (1) $ 28 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 43 $ — $ 43 $ (42) $ 1 Non-current: Derivative instruments $ — $ 187 $ — $ 187 $ (187) $ — Liabilities: Current: Derivative instruments $ — $ 291 $ — $ 291 $ (42) $ 249 Non-current: Derivative instruments $ — $ 244 $ — $ 244 $ (187) $ 57 |
Schedule of Offsetting Liabilities | The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2021 and December 31, 2020 . The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 60 $ — $ 60 $ (57) $ 3 Interest rate swaps designated as hedges $ — $ 10 $ — $ 10 $ — $ 10 Non-current: Derivative instruments $ — $ 12 $ — $ 12 $ (8) $ 4 Interest rate swaps designated as hedges $ — $ 1 $ — $ 1 $ (1) $ — Liabilities: Current: Derivative instruments $ — $ 231 $ — $ 231 $ (57) $ 174 Non-current: Derivative instruments $ — $ 9 $ — $ 9 $ (8) $ 1 Interest rate swaps designated as hedges $ — $ 29 $ — $ 29 $ (1) $ 28 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In millions) Assets: Current: Derivative instruments $ — $ 43 $ — $ 43 $ (42) $ 1 Non-current: Derivative instruments $ — $ 187 $ — $ 187 $ (187) $ — Liabilities: Current: Derivative instruments $ — $ 291 $ — $ 291 $ (42) $ 249 Non-current: Derivative instruments $ — $ 244 $ — $ 244 $ (187) $ 57 |
Schedule of 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: December 31, 2021 December 31, 2020 Carrying Carrying Value Fair Value Value Fair Value (In millions) Debt $ 6,687 $ 7,148 $ 5,815 $ 6,213 |
SUPPLEMENTAL INFORMATION TO S_2
SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Supplemental Cash Flow Information Disclosure [Abstract] | |
Schedule of Supplemental Disclosures of Cash Flow Information | Year Ended December 31, 2021 2020 2019 (In millions) Supplemental disclosure of cash flow information: Interest paid, net of capitalized interest $ 194 $ 221 $ 187 Cash paid (received) for income taxes $ (138) $ — $ — Supplemental disclosure of non-cash transactions: Accrued capital expenditures included in accounts payable and accrued expenses $ 287 $ 213 $ 553 Capitalized stock-based compensation $ 20 $ 16 $ 17 Common stock issued for business combinations $ 1,727 $ — $ — Asset retirement obligations acquired $ 65 $ 2 $ 4 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Commitments | The following is a schedule of minimum future payments with commitments that have initial or remaining noncancellable terms in excess of one year as of December 31, 2021: Year Ending December 31, Transportation Commitments (1) Sand Supply Agreement (2) Produced Water Disposal Commitments (3) (In millions) 2022 $ 82 $ 18 $ 5 2023 85 18 5 2024 81 18 5 2025 86 18 5 2026 92 5 4 Thereafter 452 — 27 Total $ 878 $ 77 $ 51 (1) The Company has committed to transport gross quantities of crude oil and natural gas on various pipelines under a variety of contracts including throughput and take-or-pay agreements. The Company’s failure to purchase the minimum level of quantities would require it to pay shortfall fees up to the amount of the original monthly commitment amounts included in the table above. (2) The Company has committed to purchase minimum quantities of sand for use in its drilling operations. Our failure to purchase the minimum level of quantities would require us to pay shortfall fees up to the commitment amounts included in the table above. (3) Rattler entered into a minimum volume commitment to purchase produced water disposal services under a 14 year agreement beginning in 2021. |
Schedule of Delivery Commitment | At December 31, 2021, the Company’s delivery commitments covered the following gross volumes of oil: Year Ending December 31, Oil Volume Commitments (Bbl/d) 2022 175,000 2023 175,000 2024 125,000 2025 125,000 2026 125,000 Thereafter 325,000 Total 1,050,000 |
SEGMENT INFORMATION (Tables)
SEGMENT INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
Schedule of Results of the Company Business Segments | The following tables summarize the results of the Company's operating segments during the periods presented: Upstream Midstream Operations Eliminations Total (In millions) Year Ended December 31, 2021: Third-party revenues $ 6,747 $ 50 $ — $ 6,797 Intersegment revenues — 371 (371) — Total revenues $ 6,747 $ 421 $ (371) $ 6,797 Depreciation, depletion, amortization and accretion $ 1,219 $ 56 $ — $ 1,275 Income (loss) from operations $ 3,879 $ 180 $ (58) $ 4,001 Interest expense, net $ (167) $ (32) $ — $ (199) Other income (expense) $ (925) $ 38 $ (8) $ (895) Provision for (benefit from) income taxes $ 620 $ 11 $ — $ 631 Net income (loss) attributable to non-controlling interest $ 57 $ 37 $ — $ 94 Net income (loss) attributable to Diamondback Energy, Inc. $ 2,110 $ 138 $ (66) $ 2,182 Total assets $ 21,329 $ 1,942 $ (373) $ 22,898 Upstream Midstream Operations Eliminations Total (In millions) Year Ended December 31, 2020: Third-party revenues $ 2,756 $ 57 $ — $ 2,813 Intersegment revenues — 367 (367) — Total revenues $ 2,756 $ 424 $ (367) $ 2,813 Depreciation, depletion, amortization and accretion $ 1,257 $ 54 $ — $ 1,311 Impairment of oil and natural gas properties $ 6,021 $ — $ — $ 6,021 Income (loss) from operations $ (5,562) $ 182 $ (96) $ (5,476) Interest expense, net $ (180) $ (17) $ — $ (197) Other income (expense) $ (87) $ (10) $ (6) $ (103) Provision for (benefit from) income taxes $ (1,114) $ 10 $ — $ (1,104) Net income (loss) attributable to non-controlling interest $ (190) $ 35 $ — $ (155) Net income (loss) attributable to Diamondback Energy, Inc. $ (4,525) $ 110 $ (102) $ (4,517) Total assets $ 16,128 $ 1,809 $ (318) $ 17,619 Upstream Midstream Operations Eliminations Total (In millions) Year Ended December 31, 2019: Third-party revenues $ 3,891 $ 73 $ — $ 3,964 Intersegment revenues — 375 (375) — Total revenues $ 3,891 $ 448 $ (375) $ 3,964 Depreciation, depletion, amortization and accretion $ 1,411 $ 43 $ — $ 1,454 Impairment of oil and natural gas properties $ 790 $ — $ — $ 790 Income (loss) from operations $ 790 $ 219 $ (314) $ 695 Interest expense, net $ (171) $ (1) $ — $ (172) Other income (expense) $ (149) $ (6) $ (6) $ (161) Provision for (benefit from) income taxes $ 21 $ 26 $ — $ 47 Net income (loss) attributable to non-controlling interest $ 75 $ 91 $ (91) $ 75 Net income (loss) attributable to Diamondback Energy, Inc. $ 374 $ 95 $ (229) $ 240 Total assets $ 22,125 $ 1,636 $ (230) $ 23,531 |
SUPPLEMENTAL INFORMATION ON O_2
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of Aggregate Capitalized Costs Related To Oil and Natural Gas Production Activities | Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: December 31, 2021 2020 (In millions) Oil and natural gas properties: Proved properties $ 24,418 $ 19,884 Unproved properties 8,496 7,493 Total oil and natural gas properties 32,914 27,377 Accumulated depletion (5,434) (4,237) Accumulated impairment (7,954) (7,954) Net oil and natural gas properties capitalized $ 19,526 $ 15,186 |
Schedule of Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities | Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows: Year Ended December 31, 2021 2020 2019 (In millions) Acquisition costs: Proved properties $ 2,805 $ 13 $ 194 Unproved properties 1,829 106 418 Development costs 516 381 956 Exploration costs 1,223 1,098 1,915 Total $ 6,373 $ 1,598 $ 3,483 |
Schedule of Results of Operations From Oil and Natural Gas Producing Activities | The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and income tax expense has been calculated by applying statutory income tax rates to oil, gas and natural gas liquids sales after deducting production costs, depreciation, depletion and amortization and accretion and impairment. Therefore, the following schedule is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations. Year Ended December 31, 2021 2020 2019 (In millions) Oil, natural gas and natural gas liquid sales $ 6,747 $ 2,756 $ 3,887 Production costs (1,202) (760) (826) Depreciation, depletion, amortization and accretion (1,211) (1,249) (1,405) Impairment — (6,021) (790) Income tax benefit (expense) (918) 1,151 (186) Results of operations $ 3,416 $ (4,123) $ 680 |
Schedule of Changes in Estimated Proved Reserves | The changes in estimated proved reserves are as follows: Oil Natural Gas Natural Gas Proved Developed and Undeveloped Reserves: As of December 31, 2018 626,936 190,291 1,048,649 Extensions and discoveries 256,569 66,572 318,874 Revisions of previous estimates (84,789) (8,166) (149,657) Purchase of reserves in place 13,974 3,813 19,830 Divestitures (33,269) (3,809) (21,272) Production (68,518) (18,498) (97,613) As of December 31, 2019 710,903 230,203 1,118,811 Extensions and discoveries 191,009 58,410 316,035 Revisions of previous estimates (78,244) 21,927 300,160 Purchase of reserves in place 2,124 778 3,512 Divestitures (209) (141) (905) Production (66,182) (21,981) (130,549) As of December 31, 2020 759,401 289,196 1,607,064 Extensions and discoveries 271,222 127,479 720,125 Revisions of previous estimates (160,570) (6,685) 195,302 Purchase of reserves in place 176,261 58,587 302,770 Divestitures (36,503) (11,597) (70,048) Production (81,522) (27,246) (169,406) As of December 31, 2021 928,289 429,734 2,585,807 Proved Developed Reserves: December 31, 2018 403,051 125,509 705,084 December 31, 2019 457,083 165,173 824,760 December 31, 2020 443,464 192,495 1,085,035 December 31, 2021 620,474 285,513 1,770,688 Proved Undeveloped Reserves: December 31, 2018 223,885 64,782 343,565 December 31, 2019 253,820 65,030 294,051 December 31, 2020 315,937 96,701 522,029 December 31, 2021 307,815 144,221 815,119 Beginning proved undeveloped reserves at December 31, 2020 499,643 Undeveloped reserves transferred to developed (172,526) Revisions (243,268) Purchases 63,013 Divestitures — Extensions and discoveries 441,027 Ending proved undeveloped reserves at December 31, 2021 587,889 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Attributable to Proved Crude Oil and Natural Gas Reserves | The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2021, 2020 and 2019: December 31, 2021 2020 2019 (In millions) Future cash inflows $ 77,085 $ 32,173 $ 40,681 Future development costs (4,243) (3,585) (3,809) Future production costs (19,123) (10,763) (9,319) Future production taxes (5,572) (2,354) (2,905) Future income tax expenses (7,237) (727) (2,635) Future net cash flows 40,910 14,744 22,013 10% discount to reflect timing of cash flows (22,193) (7,986) (11,829) Standardized measure of discounted future net cash flows (1) $ 18,717 $ 6,758 $ 10,184 |
Schedule of Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids | The table below presents the unweighted arithmetic average first-day-of–the-month price for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows: December 31, 2021 2020 2019 Oil (per Bbl) $ 64.78 $ 38.06 $ 51.88 Natural gas (per Mcf) $ 2.61 $ 0.09 $ 0.18 Natural gas liquids (per Bbl) $ 23.71 $ 10.83 $ 15.65 |
Schedule of Principal Changes in the Standardized Measure of Discounted Future Net Cash Flows Attributable to Proved Reserves | Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: Year Ended December 31, 2021 2020 2019 (In millions) Standardized measure of discounted future net cash flows at the beginning of the period $ 6,758 $ 10,184 $ 11,676 Sales of oil and natural gas, net of production costs (5,757) (2,225) (3,334) Acquisitions of reserves 1,914 30 309 Divestitures of reserves (275) (4) (500) Extensions and discoveries, net of future development costs 6,298 1,514 4,004 Previously estimated development costs incurred during the period 548 704 120 Net changes in prices and production costs 10,748 (5,273) 831 Changes in estimated future development costs (19) 526 (3,190) Revisions of previous quantity estimates 719 (462) (1,242) Accretion of discount 703 1,126 1,344 Net change in income taxes (2,841) 807 693 Net changes in timing of production and other (79) (169) (527) Standardized measure of discounted future net cash flows at the end of the period $ 18,717 $ 6,758 $ 10,184 |
DESCRIPTION OF THE BUSINESS A_2
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION (Details) - segment | 12 Months Ended | |
Dec. 31, 2021 | May 28, 2019 | |
Noncontrolling Interest [Line Items] | ||
Number of business segments | 2 | |
Rattler MIdstream LP | ||
Noncontrolling Interest [Line Items] | ||
Ownership percentage | 74.00% | 29.00% |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021USD ($)$ / Boe | Dec. 31, 2020USD ($)$ / Boe | Dec. 31, 2019USD ($)$ / Boe | |
Property, Plant and Equipment [Line Items] | |||
Depreciation, depletion and amortization excluding amortization of financing costs | $ 1,275 | $ 1,311 | $ 1,454 |
Estimated future net revenue discounted rate per annum | 10.00% | ||
Oil and Gas Properties | |||
Property, Plant and Equipment [Line Items] | |||
Average depletion rate per barrel equivalent unit of production | $ / Boe | 8.77 | 11.30 | 13.54 |
Depreciation, depletion and amortization excluding amortization of financing costs | $ 1,200 | $ 1,200 | $ 1,400 |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Property, Equipment and Land - Additional Information (Details) - Other Property and Equipment, Net | 12 Months Ended |
Dec. 31, 2021 | |
Minimum | |
Property, Plant and Equipment [Line Items] | |
Estimated useful life of property and equipment | 3 years |
Maximum | |
Property, Plant and Equipment [Line Items] | |
Estimated useful life of property and equipment | 30 years |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Accounting Policies [Abstract] | |||
Impairment of long-lived assets | $ 0 | $ 0 | $ 0 |
Remaining performance obligation, amount | 0 | ||
Equity method investment impairment | $ 0 | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Derivative liability payable | $ 101 | $ 30 |
Lease operating expenses payable | 86 | 115 |
Ad valorem taxes payable | 70 | 57 |
Accrued compensation | 48 | 27 |
Interest payable | 46 | 37 |
Midstream operating expenses payable | 13 | 18 |
Liability for drilling costs prepaid by joint interest partners | 10 | 5 |
Other | 62 | 13 |
Total other accrued liabilities | $ 436 | $ 302 |
REVENUE FROM CONTRACTS WITH C_3
REVENUE FROM CONTRACTS WITH CUSTOMERS - Revenue from Contracts with Customers (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Disaggregation of Revenue [Line Items] | |||
Revenues | $ 6,747 | $ 2,756 | $ 3,887 |
Midland Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 4,288 | 1,587 | 2,325 |
Delaware Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 2,127 | 1,161 | 1,494 |
Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 332 | 8 | 68 |
Oil sales | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 5,396 | 2,410 | 3,554 |
Oil sales | Midland Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 3,468 | 1,393 | 2,139 |
Oil sales | Delaware Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 1,663 | 1,011 | 1,351 |
Oil sales | Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 265 | 6 | 64 |
Natural gas sales | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 569 | 107 | 66 |
Natural gas sales | Midland Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 327 | 56 | 32 |
Natural gas sales | Delaware Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 215 | 50 | 33 |
Natural gas sales | Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 27 | 1 | 1 |
Natural gas liquid sales | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 782 | 239 | 267 |
Natural gas liquid sales | Midland Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 493 | 138 | 154 |
Natural gas liquid sales | Delaware Basin | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 249 | 100 | 110 |
Natural gas liquid sales | Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | $ 40 | $ 1 | $ 3 |
REVENUE FROM CONTRACTS WITH C_4
REVENUE FROM CONTRACTS WITH CUSTOMERS - Concentrations (Details) - Customer Concentration Risk - Revenue Benchmark | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Vitol Inc | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 21.00% | 26.00% | 15.00% |
Shell Trading US Company | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 19.00% | 22.00% | 27.00% |
Plains Marketing LP | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 12.00% | 20.00% | 23.00% |
Trafigura Trading LLC | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 11.00% |
ACQUISITIONS AND DIVESTITURES -
ACQUISITIONS AND DIVESTITURES - Narrative (Details) shares in Thousands | Dec. 01, 2021USD ($) | Nov. 01, 2021USD ($) | Oct. 21, 2021USD ($)a | Oct. 05, 2021USD ($)MMcf / dproperty | Oct. 01, 2021USD ($)ashares | Mar. 31, 2021USD ($) | Feb. 26, 2021USD ($)awellshares | Dec. 21, 2020USD ($) | Jul. 29, 2019USD ($)shares | Jul. 01, 2019USD ($) | May 23, 2019USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jun. 03, 2021a | Mar. 17, 2021USD ($)a |
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Proved properties | $ 2,805,000,000 | $ 13,000,000 | $ 194,000,000 | |||||||||||||
Unproved properties | 1,829,000,000 | 106,000,000 | $ 418,000,000 | |||||||||||||
Proceeds from divestiture of certain conventional and non-core assets | $ 54,000,000 | |||||||||||||||
Long-term debt, gross | 6,687,000,000 | $ 5,815,000,000 | ||||||||||||||
Permian | Disposed of by Sale | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Cash proceeds from sale | 82,000,000 | |||||||||||||||
Williston Basin | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Area of land (in acres) | a | 95,000 | |||||||||||||||
Cash proceeds from sale | $ 586,000,000 | |||||||||||||||
Loss on disposition of assets | $ 0 | |||||||||||||||
Rattler’s Gas Gathering | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Gross potential consideration | 93,000,000 | |||||||||||||||
Consideration due at closing | 83,000,000 | |||||||||||||||
Rattler’s Gas Gathering | Contingent Payment Due in 2023 | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Consideration payment | 5,000,000 | |||||||||||||||
Rattler’s Gas Gathering | Contingent Payment Due in 2024 | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Consideration payment | $ 5,000,000 | |||||||||||||||
Divestiture of Certain Conventional and Non-Core Assets | Discontinued Operations, Disposed of by Sale | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Proceeds from divestiture of certain conventional and non-core assets | $ 285,000,000 | $ 37,000,000 | ||||||||||||||
Gain (loss) from divestiture of certain conventional and non-core assets | $ 0 | $ 0 | ||||||||||||||
2019 Drop Down Transaction | Discontinued Operations, Disposed of by Sale | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Cash proceeds from sale | $ 190,000,000 | |||||||||||||||
Percentage of mineral acres operated | 95.00% | |||||||||||||||
Percentage of average net royalty interest in acquired mineral and royalty interests | 3.20% | |||||||||||||||
2019 Drop Down Transaction | Discontinued Operations, Disposed of by Sale | Viper Energy Partners LP | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Proceeds from divestiture of certain conventional and non-core assets | $ 497,000,000 | |||||||||||||||
2019 Drop Down Transaction | Discontinued Operations, Disposed of by Sale | Viper Energy Partners LP | Class B Units | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Shares newly issued (in shares) | shares | 18,000 | |||||||||||||||
QEP | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Proved properties | $ 2,000,000,000 | |||||||||||||||
Unproved properties | $ 742,000,000 | |||||||||||||||
Decrease of proved properties | (300,000,000) | |||||||||||||||
Increase of unproved properties | 300,000,000 | |||||||||||||||
Business combination, pro forma information, revenue of acquiree since acquisition date, actual | 1,100,000,000 | |||||||||||||||
Business combination, pro forma information, direct operating expenses since acquisition date, actual | 455,000,000 | |||||||||||||||
Combined tier one acres | a | 49,000 | |||||||||||||||
Exchange ratio | 0.050 | |||||||||||||||
Debt in business combination | $ 1,600,000,000 | |||||||||||||||
Acquisition related costs | 78,000,000 | |||||||||||||||
Acquisition related costs, incurred by QEP | 31,000,000 | |||||||||||||||
Rattler’s WTG Joint Venture Acquisition | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Cash payment to acquire business | $ 104,000,000 | |||||||||||||||
Joint venture, interest acquired | 25.00% | |||||||||||||||
Southern Midland Basin | Permian | Disposed of by Sale | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Area of land (in acres) | a | 7,000 | |||||||||||||||
Delaware Basin | Permian | Disposed of by Sale | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Combined tier one acres | a | 1,300 | |||||||||||||||
Midland Basin | Rattler’s WTG Joint Venture Acquisition | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Gas processing Capacity | MMcf / d | 925,000,000 | |||||||||||||||
Midland Basin | Rattler’s WTG Joint Venture Acquisition | WTG Midstream LLC | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Gas processing plants | property | 6 | |||||||||||||||
Guidon Operating LLC | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Number of shares issued | shares | 10,676 | |||||||||||||||
Payments for asset acquisition | $ 375,000,000 | $ 375,000,000 | ||||||||||||||
Number of additional wells | well | 210 | |||||||||||||||
Proved properties | 537,000,000 | |||||||||||||||
Unproved properties | 573,000,000 | |||||||||||||||
Business combination, pro forma information, revenue of acquiree since acquisition date, actual | 345,000,000 | |||||||||||||||
Business combination, pro forma information, direct operating expenses since acquisition date, actual | $ 170,000,000 | |||||||||||||||
Guidon Operating LLC | Northern Midland Basin | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Area of land (in acres) | a | 32,500 | |||||||||||||||
2021 Dropdown Transaction | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Price of acquisition | $ 160,000,000 | |||||||||||||||
Asset acquisition, property acquired | $ 160,000,000 | |||||||||||||||
Viper’s Swallowtail Acquisition | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Number of shares issued | shares | 15,250 | |||||||||||||||
Payments for asset acquisition | $ 225,000,000 | |||||||||||||||
Viper’s Swallowtail Acquisition | Viper’s Revolving Credit Facility | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Long-term debt, gross | $ 190,000,000 | |||||||||||||||
Viper’s Swallowtail Acquisition | Diamondback Energy, Inc | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Percentage of shares acquired | 62.00% | |||||||||||||||
Viper’s Swallowtail Acquisition | Northern Midland Basin | ||||||||||||||||
Business Combinations And Divestitures [Line Items] | ||||||||||||||||
Area of land (in acres) | a | 2,313 |
ACQUISITIONS AND DIVESTITURES_2
ACQUISITIONS AND DIVESTITURES - Schedule of Asset Acquisition Consideration Paid (Details) - Guidon Operating LLC - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | Feb. 26, 2021 | Dec. 21, 2020 |
Asset Acquisition [Line Items] | ||
Shares of Diamondback common stock issued at closing (shares) | 10,676 | |
Closing price per share of Diamondback common stock on the closing date (in USD per share) | $ 69.28 | |
Fair value of Diamondback common stock issued | $ 740 | |
Cash consideration | $ 375 | 375 |
Total consideration (including fair value of Diamondback common stock issued) | $ 1,115 |
ACQUISITIONS AND DIVESTITURES_3
ACQUISITIONS AND DIVESTITURES - Schedule of Purchase Price Allocation (Details) - Guidon Operating LLC $ in Millions | Dec. 21, 2020USD ($) |
Asset Acquisition [Line Items] | |
Total consideration | $ 1,115 |
Fair value of liabilities assumed: | |
Asset retirement obligations | 9 |
Fair value of assets acquired: | |
Oil and gas properties | 1,110 |
Midstream assets | 14 |
Amount attributable to assets acquired | 1,124 |
Net assets acquired and liabilities assumed | $ 1,115 |
ACQUISITIONS AND DIVESTITURES_
ACQUISITIONS AND DIVESTITURES - Schedule Of Business Acquisition Consideration Paid (Details) - QEP $ / shares in Units, $ in Millions | Mar. 17, 2021USD ($)$ / sharesshares |
Business Acquisition [Line Items] | |
Eligible shares of QEP common stock to be converted into shares of Diamondback common stock (in shares) | 238,153,000 |
Shares of QEP equity awards included in precombination consideration (in shares) | 4,221,000 |
Total shares of QEP common stock eligible for merger consideration (in shares) | 242,374,000 |
Exchange ratio | 0.050 |
Additional shares of Diamondback common stock to be issued as merger consideration (in shares) | 12,119,000 |
Business acquisition, share price (USD per share) | $ / shares | $ 81.41 |
Business combination, fair value of consideration | $ | $ 987 |
ACQUISITIONS AND DIVESTITURES_4
ACQUISITIONS AND DIVESTITURES - Schedule of Preliminary Purchase Price Allocation (Details) - QEP - USD ($) $ in Millions | Mar. 17, 2021 | Dec. 31, 2021 |
Business Combination, Consideration Transferred [Abstract] | ||
Business combination, fair value of consideration | $ 987 | |
Fair value of liabilities assumed: | ||
Accounts payable - trade | 26 | |
Accrued capital expenditures | 38 | |
Other accrued liabilities | 107 | |
Revenues and royalties payable | 67 | |
Derivative instruments | 242 | |
Long-term debt | 1,710 | |
Asset retirement obligations | 54 | |
Other long-term liabilities | 63 | |
Amount attributable to liabilities assumed | 2,307 | |
Fair value of assets acquired: | ||
Cash, cash equivalents and restricted cash | 22 | |
Accounts receivable - joint interest and other, net | 87 | |
Accounts receivable - oil and natural gas sales, net | 44 | |
Inventories | 18 | |
Income tax receivable | 33 | |
Prepaid expenses and other current assets | 7 | |
Oil and natural gas properties | 2,927 | |
Other property, equipment and land | 10 | |
Deferred income taxes | 40 | $ 40 |
Other assets | 106 | |
Amount attributable to assets acquired | 3,294 | |
Net assets acquired and liabilities assumed | $ 987 |
ACQUISITIONS AND DIVESTITURES_5
ACQUISITIONS AND DIVESTITURES - Pro Forma Financial Information (Details) - QEP - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Business Acquisition [Line Items] | ||
Revenues | $ 7,069 | $ 3,727 |
Income (loss) from operations | 4,182 | (5,771) |
Net income (loss) | $ 2,186 | $ (4,641) |
Basic earnings per common share (in dollars per share) | $ 12.09 | $ (25.67) |
Diluted earnings per common share (in dollars per share) | $ 12.05 | $ (25.67) |
ACQUISITIONS AND DIVESTITURES_6
ACQUISITIONS AND DIVESTITURES - 2020 Activity (Details) - Viper LLC - Mineral Interests In Permian Basin $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($)a | |
Asset Acquisition [Line Items] | |
Mineral properties acquired, gross acres | 4,948 |
Mineral properties acquired net royalty acres | 417 |
Total consideration | $ | $ 64 |
ACQUISITIONS AND DIVESTITURES_7
ACQUISITIONS AND DIVESTITURES - 2019 Activity (Details) | Nov. 01, 2021USD ($) | Jul. 01, 2019USD ($)a | May 23, 2019USD ($)a |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Proceeds from divestiture of certain conventional and non-core assets | $ 54,000,000 | ||
Divestiture of Certain Conventional and Non-Core Assets | Discontinued Operations, Disposed of by Sale | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Conventional and non-core Permian assets divested, area (in acre) | a | 103,750 | 6,589 | |
Proceeds from divestiture of certain conventional and non-core assets | $ 285,000,000 | $ 37,000,000 | |
Gain (loss) from divestiture of certain conventional and non-core assets | $ 0 | $ 0 |
ACQUISITIONS AND DIVESTITURES_8
ACQUISITIONS AND DIVESTITURES - 2019 Drop Down Transaction (Details) shares in Millions, $ in Millions | Nov. 01, 2021USD ($) | Jul. 29, 2019USD ($)ashares |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Proceeds from divestiture of certain conventional and non-core assets | $ 54 | |
2019 Drop Down Transaction | Discontinued Operations, Disposed of by Sale | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Cash proceeds from sale | $ 190 | |
Conventional and non-core Permian assets divested, area (in acre) | a | 5,490 | |
Percentage of mineral acres operated | 95.00% | |
Percentage of average net royalty interest in acquired mineral and royalty interests | 3.20% | |
2019 Drop Down Transaction | Discontinued Operations, Disposed of by Sale | Viper Energy Partners LP | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Proceeds from divestiture of certain conventional and non-core assets | $ 497 | |
2019 Drop Down Transaction | Discontinued Operations, Disposed of by Sale | Viper Energy Partners LP | Class B Units | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Shares newly issued (in shares) | shares | 18 |
VIPER ENERGY PARTNERS LP - Narr
VIPER ENERGY PARTNERS LP - Narrative (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||||||||
Mar. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Nov. 30, 2021 | Oct. 31, 2021 | Sep. 30, 2021 | Nov. 06, 2020 | Oct. 29, 2020 | May 31, 2019 | |
Noncontrolling Interest [Line Items] | ||||||||||
Stock repurchase program authorized amount | $ 2,000,000,000 | $ 2,000,000,000 | ||||||||
Stock repurchase program amount repurchased | $ 431,000,000 | $ 98,000,000 | $ 598,000,000 | |||||||
Stock repurchase remaining authorized amount | $ 1,600,000,000 | |||||||||
Common Stock | ||||||||||
Noncontrolling Interest [Line Items] | ||||||||||
Stock repurchase program authorized amount | $ 150,000,000 | $ 100,000,000 | ||||||||
Follow-on Public Offering | ||||||||||
Noncontrolling Interest [Line Items] | ||||||||||
Number of common units sold (in shares) | 10,925,000 | 0 | 0 | |||||||
Over-Allotment Option | ||||||||||
Noncontrolling Interest [Line Items] | ||||||||||
Number of common units sold (in shares) | 1,425,000 | |||||||||
Viper Energy Partners LP | Common Stock | ||||||||||
Noncontrolling Interest [Line Items] | ||||||||||
Stock repurchase program authorized amount | $ 150,000,000 | $ 100,000,000 | ||||||||
Stock repurchase program amount repurchased | $ 46,000,000 | |||||||||
Stock repurchase remaining authorized amount | 80,000,000 | |||||||||
Viper Energy Partners LP | Follow-on Public Offering | ||||||||||
Noncontrolling Interest [Line Items] | ||||||||||
Consideration received on transaction | $ 341,000,000 | |||||||||
Viper Energy Partners LP | ||||||||||
Noncontrolling Interest [Line Items] | ||||||||||
Limited partners' capital account, distribution amount | $ 101,000,000 | $ 62,000,000 | $ 133,000,000 | |||||||
Viper Energy Partners LP | ||||||||||
Noncontrolling Interest [Line Items] | ||||||||||
Noncontrolling interest, ownership percentage | 54.00% |
RATTLER MIDSTREAM LP (Details)
RATTLER MIDSTREAM LP (Details) - USD ($) | Dec. 21, 2021 | May 28, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Oct. 31, 2021 | Sep. 30, 2021 | Oct. 29, 2020 | May 31, 2019 |
Noncontrolling Interest [Line Items] | |||||||||
Stock repurchase program authorized amount | $ 2,000,000,000 | $ 2,000,000,000 | |||||||
Stock repurchase program amount repurchased | $ 431,000,000 | $ 98,000,000 | $ 598,000,000 | ||||||
Stock repurchase remaining authorized amount | 1,600,000,000 | ||||||||
Common Stock | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Stock repurchase program authorized amount | $ 150,000,000 | $ 100,000,000 | |||||||
Rattler LLC and Rattler Midstream GP LLC | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Limited partners' capital account, distribution amount | 97,000,000 | $ 115,000,000 | $ 36,000,000 | ||||||
Rattler MIdstream LP | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Limited partners capital contribution | $ 1,000,000 | ||||||||
General partners cash contribution | $ 1,000,000 | ||||||||
Rattler MIdstream LP | Class B Units | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Limited partners' capital account, units issued (in Shares) | 107,815,152 | ||||||||
Rattler MIdstream LP | Common Stock | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Stock repurchase program amount repurchased | 48,000,000 | ||||||||
Stock repurchase remaining authorized amount | $ 88,000,000 | ||||||||
Rattler MIdstream LP | IPO | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Offer and issuance of stock (in Shares) | 43,700,000 | ||||||||
Shares issued (in dollars per share) | $ 17.50 | ||||||||
Consideration received from offering | $ 720,000,000 | ||||||||
Rattler LLC | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Distribution to affiliates | $ 727,000,000 | ||||||||
Rattler MIdstream LP | |||||||||
Noncontrolling Interest [Line Items] | |||||||||
Ownership percentage | 29.00% | 74.00% | |||||||
Limited partners ownership percentage | 100.00% | 71.00% |
REAL ESTATE ASSETS - Schedule o
REAL ESTATE ASSETS - Schedule of Real Estate Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Real Estate [Line Items] | ||
Buildings | $ 95 | $ 102 |
Tenant improvements | 4 | 5 |
Land | 1 | 2 |
Land improvements | 1 | 1 |
Total real estate assets | 101 | 110 |
Less: accumulated depreciation | (16) | (13) |
Total investment in land and buildings, net | $ 85 | $ 97 |
Minimum | Buildings | ||
Real Estate [Line Items] | ||
Estimated Useful Lives | 20 years | |
Minimum | Tenant improvements | ||
Real Estate [Line Items] | ||
Estimated Useful Lives | 5 years | |
Minimum | Land improvements | ||
Real Estate [Line Items] | ||
Estimated Useful Lives | 5 years | |
Maximum | Buildings | ||
Real Estate [Line Items] | ||
Estimated Useful Lives | 30 years | |
Maximum | Tenant improvements | ||
Real Estate [Line Items] | ||
Estimated Useful Lives | 15 years | |
Maximum | Land improvements | ||
Real Estate [Line Items] | ||
Estimated Useful Lives | 15 years |
PROPERTY AND EQUIPMENT - Schedu
PROPERTY AND EQUIPMENT - Schedule of Property and equipment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Oil and natural gas properties: | |||
Subject to depletion | $ 24,418 | $ 19,884 | |
Not subject to depletion | 8,496 | 7,493 | |
Gross oil and natural gas properties | 32,914 | 27,377 | |
Accumulated depletion and depreciation | (13,545) | (12,314) | |
Accumulated impairment | (7,954) | (7,954) | |
Oil and natural gas properties, net | 19,526 | 15,186 | |
Midstream assets | 1,076 | 1,013 | |
Other property, equipment and land | 174 | 138 | |
Property and equipment, net | 20,619 | 16,214 | |
Oil and Gas Properties | |||
Oil and natural gas properties: | |||
Subject to depletion | 24,418 | 19,884 | |
Not subject to depletion | 8,496 | 7,493 | |
Gross oil and natural gas properties | 32,914 | 27,377 | |
Accumulated depletion and depreciation | (5,434) | (4,237) | |
Accumulated impairment | (7,954) | (7,954) | |
Oil and natural gas properties, net | 19,526 | 15,186 | |
Balance of costs not subject to depletion | 1,688 | 71 | $ 422 |
Balance of costs not subject to depletion, Thereafter | 6,315 | ||
Other Property and Equipment, Net | |||
Oil and natural gas properties: | |||
Accumulated depletion and depreciation | (157) | (123) | |
Other property, equipment and land | $ 174 | $ 138 |
PROPERTY AND EQUIPMENT - Narrat
PROPERTY AND EQUIPMENT - Narrative (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Property, Plant and Equipment [Line Items] | ||||
Capitalized internal costs | $ 60,000,000 | $ 53,000,000 | $ 49,000,000 | |
Timing of inclusion of costs in amortization calculation | 10 years | |||
Impairment of oil and natural gas properties | $ 0 | 6,021,000,000 | $ 790,000,000 | |
Exploration costs or development costs not subject to depletion | 135,000,000 | 85,000,000 | ||
Capitalized interest not subject to depletion | $ 124,000,000 | $ 51,000,000 | ||
Guidon Operating LLC And QEP Resources | ||||
Property, Plant and Equipment [Line Items] | ||||
Impairment of oil and natural gas properties | $ 0 | |||
Guidon Operating LLC | ||||
Property, Plant and Equipment [Line Items] | ||||
Unamortized cost | 1,100,000,000 | |||
QEP | ||||
Property, Plant and Equipment [Line Items] | ||||
Unamortized cost | $ 3,000,000,000 |
ASSET RETIREMENT OBLIGATIONS (D
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligations, beginning of period | $ 109 | $ 94 | |
Additional liabilities incurred | 11 | 13 | |
Liabilities acquired | 65 | 2 | $ 4 |
Liabilities settled and divested | (36) | (8) | |
Accretion expense | 9 | 7 | |
Revisions in estimated liabilities | 13 | 1 | |
Asset retirement obligations, end of period | 171 | 109 | $ 94 |
Less: current portion | 5 | 1 | |
Asset retirement obligations - long-term | $ 166 | $ 108 |
EQUITY METHOD INVESTMENTS - Inv
EQUITY METHOD INVESTMENTS - Investments (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | $ 613 | $ 533 |
Amarillo Rattler, LLC | Disposed of by Sale | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Interest | 50.00% | |
Rattler LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | $ 613 | $ 533 |
Rattler LLC | EPIC Crude Holdings, LP | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Interest | 10.00% | |
Equity method investments | $ 107 | 121 |
Rattler LLC | Gray Oak Pipeline, LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Interest | 10.00% | |
Equity method investments | $ 121 | 130 |
Rattler LLC | Wink to Webster Pipeline LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Interest | 4.00% | |
Equity method investments | $ 86 | 83 |
Rattler LLC | OMOG JV LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Interest | 60.00% | |
Equity method investments | $ 188 | 194 |
Rattler LLC | Amarillo Rattler, LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Interest | 0.00% | |
Equity method investments | $ 0 | 5 |
Rattler LLC | Remuda Midstream Holdings LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Interest | 25.00% | |
Equity method investments | $ 111 | $ 0 |
DEBT - Long-term Debt (Details)
DEBT - Long-term Debt (Details) | 1 Months Ended | 12 Months Ended | ||||
Aug. 31, 2021USD ($) | Jun. 30, 2021USD ($)derivativeinstrument | Dec. 31, 2021USD ($)well | Mar. 24, 2021 | Mar. 17, 2021 | Dec. 31, 2020USD ($) | |
Debt Instrument [Line Items] | ||||||
Long-term debt, gross | $ 6,687,000,000 | $ 5,815,000,000 | ||||
Unamortized debt issuance costs | (31,000,000) | (29,000,000) | ||||
Unamortized discount costs | (28,000,000) | (27,000,000) | ||||
Unamortized premium costs | 8,000,000 | 15,000,000 | ||||
Less: current maturities of long-term debt | (45,000,000) | (191,000,000) | ||||
Total long-term debt | 6,642,000,000 | 5,624,000,000 | ||||
Number of agreements | instrument | 2 | |||||
Fair value of interest rate swap agreements | ||||||
Debt Instrument [Line Items] | ||||||
Fair value of interest rate swap agreements | $ (18,000,000) | 0 | ||||
Number of agreements | derivative | 2 | |||||
4.625% Notes due 2021 | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 4.625% | 4.625% | ||||
Redemption, amount | $ 191,000,000 | |||||
4.625% Notes due 2021 | Secured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 4.625% | |||||
Long-term debt, gross | $ 0 | 191,000,000 | ||||
Redemption, amount | $ 191,000,000 | |||||
5.375% Senior Notes Due 2022 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.375% | 5.375% | ||||
Long-term debt, gross | $ 25,000,000 | 0 | ||||
Redemption, amount | $ 432,000,000 | |||||
7.32% Medium Term Series A due 2022 | Medium-term Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 7.32% | |||||
Long-term debt, gross | $ 20,000,000 | 20,000,000 | ||||
5.250% Senior Notes due 2023 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.25% | 5.25% | ||||
Long-term debt, gross | $ 10,000,000 | 0 | ||||
2.875% Senior Notes due 2024 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 2.875% | |||||
Long-term debt, gross | $ 1,000,000,000 | 1,000,000,000 | ||||
4.750% Senior Notes due 2025 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 4.75% | |||||
Long-term debt, gross | $ 500,000,000 | 500,000,000 | ||||
5.375% Senior Notes due 2025 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.375% | |||||
Long-term debt, gross | $ 0 | 800,000,000 | ||||
Redemption, amount | $ 432,000,000 | |||||
3.250% Senior Notes due 2026 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 3.25% | |||||
Long-term debt, gross | $ 800,000,000 | 800,000,000 | ||||
5.625% Senior Notes due 2026 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.625% | 5.625% | ||||
Long-term debt, gross | $ 14,000,000 | 0 | ||||
7.125% Medium-term Notes, Series B, due 2028 | Medium-term Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 7.125% | |||||
Long-term debt, gross | $ 100,000,000 | 100,000,000 | ||||
3.500% Senior Notes due 2029 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 3.50% | |||||
Long-term debt, gross | $ 1,200,000,000 | 1,200,000,000 | ||||
3.125% Senior Notes due 2031 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 3.125% | 3.125% | ||||
Long-term debt, gross | $ 900,000,000 | 0 | ||||
4.400% Senior Notes due 2051 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 4.40% | 4.40% | ||||
Long-term debt, gross | $ 650,000,000 | 0 | ||||
DrillCo Agreement | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, gross | $ 58,000,000 | 79,000,000 | ||||
Wells drilled and completed under joint venture agreement | well | 15 | |||||
Revolving credit facility | Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, gross | $ 0 | 23,000,000 | ||||
Viper revolving credit facility | Viper Energy Partners LP | Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, gross | $ 304,000,000 | 84,000,000 | ||||
Viper 5.375% Senior Notes due 2027 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.375% | |||||
Viper 5.375% Senior Notes due 2027 | Senior Notes | Viper Energy Partners LP | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, gross | $ 480,000,000 | 480,000,000 | ||||
Rattler revolving credit facility | Rattler LLC | Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, gross | $ 195,000,000 | 79,000,000 | ||||
Rattler 5.625% Senior Notes due 2025 | Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.625% | |||||
Rattler 5.625% Senior Notes due 2025 | Senior Notes | Rattler LLC | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, gross | $ 500,000,000 | $ 500,000,000 |
DEBT - Schedule of Long-term De
DEBT - Schedule of Long-term Debt Maturities (Details) $ in Millions | Dec. 31, 2021USD ($) |
Debt Disclosure [Abstract] | |
2022 | $ 45 |
2023 | 10 |
2024 | 1,195 |
2025 | 1,304 |
2026 | 814 |
Thereafter | 3,388 |
Total debt, net | $ 6,756 |
DEBT - Second Amended and Resta
DEBT - Second Amended and Restated Credit Facility (Details) | Jun. 02, 2021USD ($)extension | Dec. 31, 2021USD ($)letter | Dec. 31, 2020USD ($) | Dec. 31, 2019 |
Line of Credit Facility [Line Items] | ||||
Outstanding borrowings | $ 6,687,000,000 | $ 5,815,000,000 | ||
Amended And Restated Credit Agreement | ||||
Line of Credit Facility [Line Items] | ||||
Number of extensions | extension | 2 | |||
Debt instrument, term | 1 year | |||
Maximum borrowing capacity | $ 2,000,000,000 | 1,600,000,000 | ||
Additional borrowing capacity | $ 1,000,000,000 | |||
Maximum commitment | 2,600,000,000 | |||
Swingline Loans | ||||
Line of Credit Facility [Line Items] | ||||
Long-term line of credit | $ 100,000,000 | |||
Company Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Number of letters of credit outstanding | letter | 3,000,000 | |||
Weighted average interest rate | 1.67% | 2.02% | 4.10% | |
Debt covenant, total net debt to capitalization ratio | 65.00% | |||
Debt covenant, debt principal amount as percentage of net tangible assets | 15.00% | |||
Company Credit Facility | Federal Funds Rate | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.50% | |||
Company Credit Facility | LIBOR | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.00% | |||
Company Credit Facility | Investment Grade Annually | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.15% | |||
Company Credit Facility | Investment Grade Annually | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.35% | |||
Company Credit Facility | Investment Grade Annually | Base Rate | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.25% | |||
Company Credit Facility | Investment Grade Annually | Base Rate | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.125% | |||
Company Credit Facility | Investment Grade Annually | LIBOR | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.25% | |||
Company Credit Facility | Investment Grade Annually | LIBOR | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 2.125% |
DEBT - 2021 Issuances of Notes
DEBT - 2021 Issuances of Notes (Details) - USD ($) | Mar. 24, 2021 | Dec. 31, 2021 | Dec. 31, 2020 |
Debt Instrument [Line Items] | |||
Unamortized discount | $ 28,000,000 | $ 27,000,000 | |
0.900% Senior Notes due 2023 | Senior Notes | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 650,000,000 | ||
Stated interest rate | 0.90% | ||
3.125% Senior Notes due 2031 | Senior Notes | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 900,000,000 | ||
Stated interest rate | 3.125% | 3.125% | |
4.400% Senior Notes due 2051 | Senior Notes | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 650,000,000 | ||
Stated interest rate | 4.40% | 4.40% | |
March 2021 Notes | |||
Debt Instrument [Line Items] | |||
Unamortized discount | $ 24,000,000 | ||
Proceeds from debt | $ 2,180,000,000 | ||
Debt, redemption price, percentage | 100.00% | ||
Debt, redemption price, percentage upon change of control triggering event | 101.00% |
DEBT - 2021 Redemptions of Note
DEBT - 2021 Redemptions of Notes (Details) - USD ($) | Nov. 01, 2021 | Mar. 31, 2021 | Aug. 31, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Mar. 17, 2021 | Dec. 20, 2016 |
Debt Instrument [Line Items] | ||||||||||
Outstanding borrowings | $ 6,687,000,000 | $ 5,815,000,000 | ||||||||
Cash consideration of debt | 3,193,000,000 | 239,000,000 | $ 1,250,000,000 | |||||||
Loss on extinguishment of debt | $ 75,000,000 | 5,000,000 | $ 56,000,000 | |||||||
5.375% Senior Notes Due 2022 | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | $ 478,000,000 | |||||||||
Stated interest rate | 5.375% | 5.375% | ||||||||
Outstanding borrowings | $ 25,000,000 | 0 | ||||||||
Debt | $ 453,000,000 | |||||||||
Effective percentage | 94.65% | |||||||||
Redemption, amount | $ 432,000,000 | |||||||||
5.250% Senior Notes due 2023 | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | $ 673,000,000 | |||||||||
Stated interest rate | 5.25% | 5.25% | ||||||||
Outstanding borrowings | $ 10,000,000 | 0 | ||||||||
Debt | $ 663,000,000 | |||||||||
Effective percentage | 98.43% | |||||||||
5.625% Senior Notes due 2026 | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | $ 558,000,000 | |||||||||
Stated interest rate | 5.625% | 5.625% | ||||||||
Outstanding borrowings | $ 14,000,000 | 0 | ||||||||
Debt | $ 538,000,000 | |||||||||
Effective percentage | 96.35% | |||||||||
QEP Notes | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Outstanding borrowings | $ 1,650,000,000 | |||||||||
Cash consideration of debt | $ 1,700,000,000 | |||||||||
Redemption premium fees | 152,000,000 | |||||||||
Loss on extinguishment of debt | $ 47,000,000 | |||||||||
5.375% Senior Notes due 2025 | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 5.375% | |||||||||
Outstanding borrowings | $ 0 | $ 800,000,000 | ||||||||
Cash consideration of debt | $ 381,000,000 | |||||||||
Redemption premium fees | 12,000,000 | 13,000,000 | ||||||||
Repurchased face amount | $ 368,000,000 | $ 368,000,000 | ||||||||
Percentage of outstanding debt | 45.97% | 45.97% | ||||||||
Redemption, amount | 432,000,000 | |||||||||
Cash consideration paid for redemption | $ 449,000,000 | |||||||||
5.375% Senior Notes due 2025 | Senior Notes | Debt, Repurchased in March 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Loss on extinguishment of debt | 14,000,000 | |||||||||
5.375% Senior Notes due 2025 | Senior Notes | Debt, Repurchased in August 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Loss on extinguishment of debt | $ 12,000,000 | |||||||||
Existing 2025 Senior Notes | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 5.375% | |||||||||
4.625% Notes due 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.625% | 4.625% | ||||||||
Redemption, amount | $ 191,000,000 | |||||||||
2023 Notes | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Redemption, amount | $ 650,000,000 | |||||||||
Debt, redemption price, percentage | 100.00% |
DEBT - Viper's Credit Agreement
DEBT - Viper's Credit Agreement (Details) | Jun. 02, 2021redetermination | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019 | Nov. 15, 2021USD ($) |
Line of Credit Facility [Line Items] | |||||
Long-term debt, gross | $ 6,687,000,000 | $ 5,815,000,000 | |||
Viper revolving credit facility | |||||
Line of Credit Facility [Line Items] | |||||
Maximum borrowing capacity | $ 2,000,000,000 | ||||
Current borrowing base | $ 580,000,000 | ||||
Number of additional redeterminations that may be requested | redetermination | 3 | ||||
Period of redeterminations | 12 months | ||||
Remaining borrowing capacity | $ 196,000,000 | ||||
Weighted average interest rate | 2.35% | 2.20% | 4.51% | ||
Issuance of unsecured debt | $ 1,000,000,000 | ||||
Financial covenant, reduction of borrowing base (percentage) | 25.00% | ||||
Viper revolving credit facility | LIBOR | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 1.00% | ||||
Viper revolving credit facility | Federal Funds Rate | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 0.50% | ||||
Viper revolving credit facility | Minimum | |||||
Line of Credit Facility [Line Items] | |||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.375% | ||||
Viper revolving credit facility | Minimum | LIBOR | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 2.00% | ||||
Viper revolving credit facility | Minimum | Base Rate | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 1.00% | ||||
Viper revolving credit facility | Maximum | |||||
Line of Credit Facility [Line Items] | |||||
Ratio of secured debt to EBITDAX, as defined in the credit agreement | 2.5 | ||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.50% | ||||
Viper revolving credit facility | Maximum | LIBOR | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 3.00% | ||||
Viper revolving credit facility | Maximum | Base Rate | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 2.00% | ||||
Viper revolving credit facility | Viper Energy Partners LP | |||||
Line of Credit Facility [Line Items] | |||||
Maximum borrowing capacity | $ 500,000,000 | ||||
Viper revolving credit facility | Viper Energy Partners LP | Revolving Credit Facility | |||||
Line of Credit Facility [Line Items] | |||||
Long-term debt, gross | $ 304,000,000 | $ 84,000,000 |
DEBT - Financial Covenant Table
DEBT - Financial Covenant Table (Details) | 12 Months Ended |
Dec. 31, 2021 | |
Maximum | Rattler revolving credit facility | Revolving Credit Facility | |
Line of Credit Facility [Line Items] | |
Consolidated total leverage ratio | 5 |
Line of credit, covenant terms, consolidated total leverage ratio, for three fiscal quarters following certain acquisitions | 5.50 |
Covenant terms, consolidated total leverage ratio when financial covenant election is made | 5.25 |
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 | 3.50 |
Maximum | Viper revolving credit facility | |
Line of Credit Facility [Line Items] | |
Ratio of total net debt to EBITDAX, as defined in the credit agreement | 4 |
Ratio of secured debt to EBITDAX, as defined in the credit agreement | 2.5 |
Minimum | Rattler revolving credit facility | Revolving Credit Facility | |
Line of Credit Facility [Line Items] | |
Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) | 2.50 |
Minimum | Viper revolving credit facility | |
Line of Credit Facility [Line Items] | |
Ratio of current assets to liabilities, as defined in the credit agreement | 1 |
DEBT - Rattler's Credit Agreeme
DEBT - Rattler's Credit Agreement (Details) - USD ($) | Dec. 21, 2021 | May 28, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Line of Credit Facility [Line Items] | |||||
Long-term debt, gross | $ 6,687,000,000 | $ 5,815,000,000 | |||
Rattler MIdstream LP | |||||
Line of Credit Facility [Line Items] | |||||
Members ownership percentage | 100.00% | 71.00% | |||
Rattler revolving credit facility | Revolving Credit Facility | Minimum | |||||
Line of Credit Facility [Line Items] | |||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.25% | ||||
Rattler revolving credit facility | Revolving Credit Facility | Minimum | Prime Rate | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 0.25% | ||||
Rattler revolving credit facility | Revolving Credit Facility | Minimum | LIBOR | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 1.25% | ||||
Rattler revolving credit facility | Revolving Credit Facility | Maximum | |||||
Line of Credit Facility [Line Items] | |||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.375% | ||||
Rattler revolving credit facility | Revolving Credit Facility | Maximum | Prime Rate | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 1.25% | ||||
Rattler revolving credit facility | Revolving Credit Facility | Maximum | LIBOR | |||||
Line of Credit Facility [Line Items] | |||||
Basis spread on variable rate | 2.25% | ||||
Rattler revolving credit facility | Revolving Credit Facility | Rattler LLC | |||||
Line of Credit Facility [Line Items] | |||||
Maximum borrowing capacity | $ 600,000,000 | ||||
Maximum borrowing capacity, subject to commitments | 1,000,000,000 | ||||
Long-term debt, gross | 195,000,000 | $ 79,000,000 | |||
Remaining borrowing capacity | $ 405,000,000 | ||||
Weighted average interest rate | 1.41% | 2.10% | 3.13% |
DEBT - Interest Expense (Detail
DEBT - Interest Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |||
Interest expense | $ 277 | $ 250 | $ 235 |
Other fees and expenses | 11 | 6 | 4 |
Less: interest income | 1 | 4 | 1 |
Less: capitalized interest | 88 | 55 | 66 |
Interest expense, net | $ 199 | $ 197 | $ 172 |
STOCKHOLDERS_ EQUITY AND EARN_3
STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Narrative (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2021 | May 31, 2019 | |
Equity [Abstract] | |||||
Stock repurchase program authorized amount | $ 2,000,000,000 | $ 2,000,000,000 | |||
Treasury Stock acquired | $ 431,000,000 | ||||
Stock repurchase remaining authorized amount | 1,600,000,000 | ||||
Stock repurchase program amount repurchased | $ 431,000,000 | $ 98,000,000 | $ 598,000,000 |
STOCKHOLDERS_ EQUITY AND EARN_4
STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Change in Ownership of Consolidated Subsidiaries (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Net income (loss) attributable to Diamondback Energy, Inc. | $ 2,182 | $ (4,517) | $ 240 |
Change in ownership of consolidated subsidiaries, net | (19) | (8) | 12 |
Additional Paid-in Capital | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Change in ownership of consolidated subsidiaries, net | 66 | 358 | (33) |
Rattler LLC | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Change in ownership of consolidated subsidiaries, net | 329 | ||
Rattler LLC | Additional Paid-in Capital | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Change in ownership of consolidated subsidiaries, net | 329 | ||
Limited Partner | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Net income (loss) attributable to Diamondback Energy, Inc. | 2,182 | (4,517) | 240 |
Change in ownership of consolidated subsidiaries, net | 66 | 358 | (33) |
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest | $ 2,248 | $ (4,159) | $ 207 |
STOCKHOLDERS_ EQUITY AND EARN_5
STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Basic: | |||
Net income (loss) attributable to common stock | $ 2,182 | $ (4,517) | $ 240 |
Basic weighted average common units outstanding (in shares) | 176,643,000 | 157,976,000 | 163,493,000 |
Effect of dilutive securities: | |||
Potential common shares issuable (in shares) | 716,000 | 0 | 350,000 |
Diluted: | |||
Diluted weighted average common shares outstanding (in shares) | 177,359,000 | 157,976,000 | 163,843,000 |
Basic net income attributable to common stock (in dollars per share) | $ 12.35 | $ (28.59) | $ 1.47 |
Diluted net income attributable to common stock (in dollars per share) | $ 12.30 | $ (28.59) | $ 1.47 |
Antidilutive securities, restricted stock units (in shares) | 115,865 | 696,223 |
EQUITY-BASED COMPENSATION - Nar
EQUITY-BASED COMPENSATION - Narratives (Details) - Equity Plan - shares shares in Millions | Dec. 31, 2021 | Jun. 02, 2021 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common stock reserved for future issuance (in shares) | 11.8 | 8.3 |
Common stock available for future grants (in shares) | 6.9 |
EQUITY-BASED COMPENSATION - Sch
EQUITY-BASED COMPENSATION - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 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 | $ 20 | $ 16 | $ 17 |
General and administrative expenses | |||
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items] | |||
General and administrative expenses | $ 51 | $ 37 | $ 48 |
EQUITY-BASED COMPENSATION - Res
EQUITY-BASED COMPENSATION - Restricted Stock Units (Details) - Equity Plan - Restricted Stock Units (RSUs) | 12 Months Ended |
Dec. 31, 2021$ / sharesshares | |
Restricted Stock Units | |
Unvested, beginning balance (in shares) | shares | 1,113,480 |
Granted (in shares) | shares | 776,045 |
Vested (in shares) | shares | (713,777) |
Forfeited (in shares) | shares | (96,159) |
Unvested, ending balance (in shares) | shares | 1,079,589 |
Weighted Average Grant-Date Fair Value | |
Unvested, beginning balance (in dollars per share) | $ / shares | $ 48.58 |
Granted (in dollars per share) | $ / shares | 82.98 |
Vested (in dollars per share) | $ / shares | 65.07 |
Forfeited (in dollars per share) | $ / shares | 52.14 |
Unvested, ending balance (in dollars per share) | $ / shares | $ 62.09 |
EQUITY-BASED COMPENSATION - R_2
EQUITY-BASED COMPENSATION - Restricted Stock Units - Narrative (Details) - Restricted Stock Units (RSUs) - Equity Plan - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Aggregated fair value of restricted stock | $ 46 | $ 25 | $ 45 |
Share based award not recognized | $ 52 | ||
Unrecognized compensation cost, expected period of recognition | 2 years |
EQUITY-BASED COMPENSATION - Per
EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Units - Narrative (Details) - Performance Shares - Equity Plan $ in Millions | Dec. 31, 2021USD ($) | Mar. 31, 2021shares | Mar. 31, 2020shares | Mar. 31, 2019installmentshares | Dec. 31, 2021USD ($)shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Performance shares, performance period | 3 years | 3 years | |||
Granted (in shares) | 198,454 | 225,047 | 199,723 | 198,454 | |
Percent of shares vested | 100.00% | ||||
Number of vesting installments | installment | 5 | ||||
Share based award not recognized | $ | $ 26 | $ 26 | |||
Unrecognized compensation cost, expected period of recognition | 1 year 10 months 24 days | ||||
Share-based Payment Arrangement, Tranche One | |||||
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 | 250.00% | 250.00% | 100.00% | ||
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% | 0.00% | 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% | 200.00% | 200.00% | ||
Share-based Payment Arrangement, Tranche Two | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Granted (in shares) | 32,958 | ||||
Share-based Payment Arrangement, Tranche Two | 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 Two | 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 - P_2
EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Activity (Details) - Performance Shares - Equity Plan - $ / shares | 1 Months Ended | 12 Months Ended | ||||
Mar. 31, 2021 | Mar. 31, 2020 | Mar. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Fair Value Assumptions | ||||||
Grant-date fair value (in dollars per share) | $ 131.06 | $ 70.17 | $ 137.22 | |||
Risk-free rate | 0.15% | 0.86% | 2.55% | |||
Company volatility | 69.60% | 36.70% | 35.00% | |||
Performance Restricted Stock Units | ||||||
Unvested, beginning balance (in shares) | 411,587 | |||||
Granted (in shares) | 198,454 | 225,047 | 199,723 | 198,454 | ||
Vested (in shares) | (153,582) | |||||
Forfeited (in shares) | 0 | |||||
Unvested, ending balance (in shares) | 456,459 | 411,587 | ||||
Weighted Average Grant-Date Fair Value | ||||||
Unvested, beginning balance (in dollars per share) | $ 99.10 | |||||
Granted (in dollars per share) | 131.06 | |||||
Vested (in dollars per share) | 137.22 | |||||
Forfeited (in dollars per share) | 0 | |||||
Unvested, ending balance (in dollars per share) | $ 100.17 | $ 99.10 | ||||
Maximum units could be awarded (in shares) | 1,091,711 | |||||
Five-Year | ||||||
Fair Value Assumptions | ||||||
Grant-date fair value (in dollars per share) | $ 132.48 |
EQUITY-BASED COMPENSATION - Rat
EQUITY-BASED COMPENSATION - Rattler Long-Term Incentive Plan - Narrative (Details) - Rattler Midstream LP Long-Term Incentive Plan $ in Millions | 12 Months Ended | |
Dec. 31, 2021USD ($)distributionRightshares | May 22, 2019shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common stock reserved for future issuance (in shares) | shares | 12,696,146 | 15,200,000 |
Distribution paid on unit (in shares) | distributionRight | 1 | |
Phantom Share Units (PSUs) | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Aggregated fair value | $ | $ 9 | |
Share based award not recognized | $ | $ 23 | |
Unrecognized compensation cost, expected period of recognition | 2 years 3 months 18 days | |
Partnership Unit | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Shares converted (in shares) | shares | 1 |
EQUITY-BASED COMPENSATION - R_3
EQUITY-BASED COMPENSATION - Rattler Long-Term Incentive Plan (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan | 12 Months Ended |
Dec. 31, 2021$ / sharesshares | |
Phantom Units | |
Unvested, beginning balance (in shares) | shares | 2,089,668 |
Granted (in shares) | shares | 259,916 |
Vested (in shares) | shares | (571,341) |
Forfeited (in shares) | shares | (40,718) |
Unvested, ending balance (in shares) | shares | 1,737,525 |
Weighted Average Grant-Date Fair Value | |
Unvested, beginning balance (in dollars per share) | $ / shares | $ 17.07 |
Granted (in dollars per share) | $ / shares | 11.07 |
Vested (in dollars per share) | $ / shares | 16.34 |
Forfeited (in dollars per share) | $ / shares | 7.28 |
Unvested, ending balance (in dollars per share) | $ / shares | $ 16.64 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) - USD ($) | Mar. 27, 2020 | Sep. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2017 | Mar. 17, 2021 |
Operating Loss Carryforwards [Line Items] | ||||||||
Effective income tax rate | 21.70% | 19.10% | 13.00% | |||||
Current income tax expense (benefit) | $ 25,000,000 | $ (62,000,000) | $ 0 | |||||
Change in enacted tax rate, amount | $ 179,000,000 | |||||||
Tax refund | $ 50,000,000 | $ 100,000,000 | ||||||
Net deferred tax liabilities | 1,298,000,000 | 710,000,000 | ||||||
Operating loss carryforwards, subject to expiration | 500,000,000 | |||||||
Operating loss carryforwards, not subject to expiration | 2,000,000,000 | |||||||
Valuation allowance | (315,000,000) | (166,000,000) | ||||||
Deferred tax liability includes deferred tax asset | 163,000,000 | 150,000,000 | ||||||
Net operating loss and carryforwards | 682,000,000 | 524,000,000 | ||||||
Rattler's investment in Rattler LLC | 40,000,000 | 58,000,000 | ||||||
Interest associated with uncertain tax positions (less than) | 200,000 | |||||||
Penalties associated with uncertain tax positions | $ 0 | $ 0 | ||||||
Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | ||||||
Viper LLC | ||||||||
Operating Loss Carryforwards [Line Items] | ||||||||
Valuation allowance | $ (169,000,000) | |||||||
Deferred tax liability includes deferred tax asset | 6,000,000 | |||||||
Operating loss carryforwards | 29,000,000 | |||||||
Rattler MIdstream LP | ||||||||
Operating Loss Carryforwards [Line Items] | ||||||||
Operating loss carryforwards | 108,000,000 | |||||||
Net operating loss and carryforwards | 23,000,000 | |||||||
State | ||||||||
Operating Loss Carryforwards [Line Items] | ||||||||
Valuation allowance | (6,000,000) | $ (117,000,000) | ||||||
QEP | ||||||||
Operating Loss Carryforwards [Line Items] | ||||||||
Deferred income taxes | $ 40,000,000 | 40,000,000 | ||||||
Valuation allowance | $ (23,000,000) |
INCOME TAXES - Components of In
INCOME TAXES - Components of Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current income tax provision (benefit): | |||
Federal | $ 10 | $ (62) | $ 0 |
State | 15 | 0 | 0 |
Total current income tax provision (benefit) | 25 | (62) | 0 |
Deferred income tax provision (benefit): | |||
Federal | 594 | (1,010) | 40 |
State | 12 | (32) | 7 |
Total deferred income tax provision (benefit) | 606 | (1,042) | 47 |
Provision for (benefit from) income taxes | $ 631 | $ (1,104) | $ 47 |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense at the federal statutory rate | $ 610 | $ (1,213) | $ 76 |
Income tax benefit relating to net operating loss carryback | 0 | (25) | 0 |
State income tax expense, net of federal tax effect | 23 | (30) | 6 |
Non-deductible compensation | 10 | 6 | 4 |
Change in valuation allowance | (12) | 153 | 0 |
Deferred taxes related to change in Viper LP's tax status | 0 | 0 | (42) |
Other, net | 0 | 5 | 3 |
Provision for (benefit from) income taxes | $ 631 | $ (1,104) | $ 47 |
INCOME TAXES - Components of De
INCOME TAXES - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Deferred tax assets: | ||
Net operating loss and other carryforwards | $ 682 | $ 524 |
Derivative instruments | 36 | 60 |
Stock based compensation | 5 | 7 |
Viper's investment in Viper LLC | 163 | 150 |
Rattler's investment in Rattler LLC | 40 | 58 |
Other | 22 | 8 |
Deferred tax assets | 948 | 807 |
Valuation allowance | (315) | (166) |
Deferred tax assets, net of valuation allowance | 633 | 641 |
Deferred tax liabilities: | ||
Oil and natural gas properties and equipment | 1,702 | 1,156 |
Midstream investments | 224 | 192 |
Other | 5 | 3 |
Total deferred tax liabilities | 1,931 | 1,351 |
Net deferred tax liabilities | $ 1,298 | $ 710 |
INCOME TAXES - Unrecognized Tax
INCOME TAXES - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns | ||
Balance at beginning of year | $ 7 | $ 7 |
Increase resulting from prior period tax positions | 0 | 0 |
Increase resulting from current period tax positions | 0 | 0 |
Balance at end of year | 7 | 7 |
Less: Effects of temporary items | (4) | (5) |
Total that, if recognized, would impact the effective income tax rate as of the end of the year | $ 3 | $ 2 |
DERIVATIVES - Open Derivative P
DERIVATIVES - Open Derivative Positions (Details) | 12 Months Ended |
Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl | |
2022 | July - Dec. | Brent Swaption | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 8,250 |
Weighted Average Differential | 68.62 |
OIL | 2022 | Jan. - June | Swap | WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 1,000 |
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | 45 |
OIL | 2022 | Jan. - June | Swap | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 13,900 |
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | 67.54 |
OIL | 2022 | Jan. - June | Basis Swap | Argus WTI Midland | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 17,000 |
Weighted Average Differential | 0.66 |
OIL | 2022 | July - Dec. | Basis Swap | Argus WTI Midland | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 10,000 |
Weighted Average Differential | 0.84 |
OIL | 2022 | Jan. - Dec. | Roll Swap | WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 30,000 |
Weighted Average Differential | 0.65 |
OIL | 2022 | Jan. - Dec. | Basis Put | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 50,000 |
Weighted Average Differential | (10.40) |
Derivative, Option Premium | 0.78 |
OIL | 2022 | Jan. - Mar. | Costless Collar | WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 19,500 |
Derivative, Floor Price | 46.28 |
Derivative, Cap Price | 72.67 |
OIL | 2022 | Jan. - Mar. | Costless Collar | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 55,000 |
Derivative, Floor Price | 45.55 |
Derivative, Cap Price | 71.08 |
OIL | 2022 | Jan. - Mar. | Costless Collar | Argus WTI Houston | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 22,000 |
Derivative, Floor Price | 45.91 |
Derivative, Cap Price | 70.95 |
OIL | 2022 | Jan. - Mar. | Put | WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 9,500 |
Strike Price | 47.51 |
Derivative, Option Premium | 1.57 |
OIL | 2022 | Jan. - Mar. | Put | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 14,000 |
Strike Price | 50 |
Derivative, Option Premium | 1.66 |
OIL | 2022 | Apr. - June | Costless Collar | WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 13,000 |
Derivative, Floor Price | 46.92 |
Derivative, Cap Price | 75 |
OIL | 2022 | Apr. - June | Costless Collar | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 34,000 |
Derivative, Floor Price | 46.47 |
Derivative, Cap Price | 77 |
OIL | 2022 | Apr. - June | Costless Collar | Argus WTI Houston | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 26,000 |
Derivative, Floor Price | 46.92 |
Derivative, Cap Price | 72.78 |
OIL | 2022 | Apr. - June | Put | WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 8,000 |
Strike Price | 47.50 |
Derivative, Option Premium | 1.55 |
OIL | 2022 | Apr. - June | Put | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 24,000 |
Strike Price | 50 |
Derivative, Option Premium | 1.80 |
OIL | 2022 | July - Sep. | Costless Collar | WTI | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 4,000 |
Derivative, Floor Price | 45 |
Derivative, Cap Price | 92.65 |
OIL | 2022 | July - Sep. | Costless Collar | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 11,000 |
Derivative, Floor Price | 47.73 |
Derivative, Cap Price | 78.65 |
OIL | 2022 | July - Sep. | Costless Collar | Argus WTI Houston | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 10,000 |
Derivative, Floor Price | 50 |
Derivative, Cap Price | 76.66 |
OIL | 2022 | July - Sep. | Put | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 20,000 |
Strike Price | 50 |
Derivative, Option Premium | 1.84 |
OIL | 2022 | Oct. - Dec. | Costless Collar | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 5,000 |
Derivative, Floor Price | 45 |
Derivative, Cap Price | 75.56 |
OIL | 2022 | Oct. - Dec. | Put | Brent | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 16,000 |
Strike Price | 50 |
Derivative, Option Premium | 1.84 |
OIL | 2022 | Oct. - Dec. | Put | Argus WTI Houston | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 6,000 |
Strike Price | 50 |
Derivative, Option Premium | 1.88 |
OIL | 2022 | Jan. - Sep. | Put | Argus WTI Houston | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 8,000 |
Strike Price | 50 |
Derivative, Option Premium | 1.93 |
NATURAL GAS | 2022 | July - Dec. | Costless Collar | Henry Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 260,000 |
Derivative, Floor Price | 2.67 |
Derivative, Cap Price | 5.40 |
NATURAL GAS | 2022 | Jan. - Dec. | Basis Swap | Waha Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 230,000 |
Weighted Average Differential | $ / MMBTU | (0.36) |
NATURAL GAS | 2022 | Jan. - Mar. | Costless Collar | Henry Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 350,000 |
Derivative, Floor Price | 2.67 |
Derivative, Cap Price | 4.76 |
NATURAL GAS | 2022 | Apr. - June | Costless Collar | Henry Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 370,000 |
Derivative, Floor Price | 2.64 |
Derivative, Cap Price | 4.89 |
NATURAL GAS | 2023 | Jan. - June | Basis Swap | Waha Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 60,000 |
Weighted Average Differential | (0.57) |
NATURAL GAS | 2023 | July - Dec. | Basis Swap | Waha Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 40,000 |
Weighted Average Differential | (0.60) |
NATURAL GAS | 2023 | Jan. - Mar. | Costless Collar | Henry Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 80,000 |
Derivative, Floor Price | 2.75 |
Derivative, Cap Price | 6.83 |
NATURAL GAS | 2023 | Apr. - Dec. | Costless Collar | Henry Hub | |
Derivative [Line Items] | |
Volume, energy measure (MMBtu) | MMBTU | 60,000 |
Derivative, Floor Price | 2.75 |
Derivative, Cap Price | 5.72 |
DERIVATIVES - Interest Rate Swa
DERIVATIVES - Interest Rate Swaps (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jun. 30, 2021USD ($)derivativeinstrument | |
Offsetting Assets [Line Items] | ||||
Number of agreements | instrument | 2 | |||
Net cash received (paid) on settlements: | $ (1,225) | $ 250 | $ 80 | |
Interest Rate Contract | ||||
Offsetting Assets [Line Items] | ||||
Notional amount | $ 600 | |||
Net cash received (paid) on settlements: | $ 80 | $ 0 | $ 43 | |
Interest Rate Contract | Designated as Hedging Instrument | LIBOR | ||||
Offsetting Assets [Line Items] | ||||
Average variable interest rate | 2.1865% | |||
Interest Rate Swap | ||||
Offsetting Assets [Line Items] | ||||
Number of agreements | derivative | 2 | |||
Interest Rate Swap | Senior Notes Due 2029 | Designated as Hedging Instrument | Senior Notes | ||||
Offsetting Assets [Line Items] | ||||
Fair value hedges | $ 1,200 | |||
Derivative, fixed interest rate | 3.50% |
DERIVATIVES - Gains and Losses
DERIVATIVES - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments, net: | $ (848) | $ (81) | $ (108) |
Net cash received (paid) on settlements: | (1,225) | 250 | 80 |
Cash received on contract | 16 | ||
Commodity contracts | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments, net: | (978) | (32) | (151) |
Net cash received (paid) on settlements: | (1,305) | 250 | 37 |
Cash received on contract | 17 | ||
Interest rate swaps | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments, net: | 130 | (49) | 43 |
Net cash received (paid) on settlements: | $ 80 | $ 0 | $ 43 |
FAIR VALUE MEASUREMENTS - Recur
FAIR VALUE MEASUREMENTS - Recurring Measurements (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Current: | ||
Net Fair Value Presented in Balance Sheet | $ 13 | $ 1 |
Non-current: | ||
Net Fair Value Presented in Balance Sheet | 4 | 0 |
Current: | ||
Net Fair Value Presented in Balance Sheet | 174 | 249 |
Non-current: | ||
Net Fair Value Presented in Balance Sheet | 29 | 57 |
Recurring | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 60 | 43 |
Gross Amounts Offset in Balance Sheet | (57) | (42) |
Net Fair Value Presented in Balance Sheet | 3 | 1 |
Non-current: | ||
Total Gross Fair Value | 12 | 187 |
Gross Amounts Offset in Balance Sheet | (8) | (187) |
Net Fair Value Presented in Balance Sheet | 4 | 0 |
Current: | ||
Total Gross Fair Value | 231 | 291 |
Gross Amounts Offset in Balance Sheet | (57) | (42) |
Net Fair Value Presented in Balance Sheet | 174 | 249 |
Non-current: | ||
Total Gross Fair Value | 9 | 244 |
Gross Amounts Offset in Balance Sheet | (8) | (187) |
Net Fair Value Presented in Balance Sheet | 1 | 57 |
Recurring | Interest rate swaps designated as hedges | ||
Current: | ||
Total Gross Fair Value | 10 | |
Gross Amounts Offset in Balance Sheet | 0 | |
Net Fair Value Presented in Balance Sheet | 10 | |
Non-current: | ||
Total Gross Fair Value | 1 | |
Gross Amounts Offset in Balance Sheet | (1) | |
Net Fair Value Presented in Balance Sheet | 0 | |
Non-current: | ||
Total Gross Fair Value | 29 | |
Gross Amounts Offset in Balance Sheet | (1) | |
Net Fair Value Presented in Balance Sheet | 28 | |
Recurring | Level 1 | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 0 | 0 |
Non-current: | ||
Total Gross Fair Value | 0 | 0 |
Current: | ||
Total Gross Fair Value | 0 | 0 |
Non-current: | ||
Total Gross Fair Value | 0 | 0 |
Recurring | Level 1 | Interest rate swaps designated as hedges | ||
Current: | ||
Total Gross Fair Value | 0 | |
Non-current: | ||
Total Gross Fair Value | 0 | |
Non-current: | ||
Total Gross Fair Value | 0 | |
Recurring | Level 2 | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 60 | 43 |
Non-current: | ||
Total Gross Fair Value | 12 | 187 |
Current: | ||
Total Gross Fair Value | 231 | 291 |
Non-current: | ||
Total Gross Fair Value | 9 | 244 |
Recurring | Level 2 | Interest rate swaps designated as hedges | ||
Current: | ||
Total Gross Fair Value | 10 | |
Non-current: | ||
Total Gross Fair Value | 1 | |
Non-current: | ||
Total Gross Fair Value | 29 | |
Recurring | Level 3 | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 0 | 0 |
Non-current: | ||
Total Gross Fair Value | 0 | 0 |
Current: | ||
Total Gross Fair Value | 0 | 0 |
Non-current: | ||
Total Gross Fair Value | 0 | $ 0 |
Recurring | Level 3 | Interest rate swaps designated as hedges | ||
Current: | ||
Total Gross Fair Value | 0 | |
Non-current: | ||
Total Gross Fair Value | 0 | |
Non-current: | ||
Total Gross Fair Value | $ 0 |
FAIR VALUE MEASUREMENTS - Asset
FAIR VALUE MEASUREMENTS - Asset and Liabilities Not Recorded at Fair Value (Details) - Nonrecurring - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Carrying Value | ||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | ||
Debt | $ 6,687 | $ 5,815 |
Value | ||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | ||
Debt | $ 7,148 | $ 6,213 |
SUPPLEMENTAL INFORMATION TO S_3
SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Supplemental disclosure of cash flow information: | |||
Interest paid, net of capitalized interest | $ 194 | $ 221 | $ 187 |
Cash paid (received) for income taxes | (138) | 0 | 0 |
Supplemental disclosure of non-cash transactions: | |||
Accrued capital expenditures included in accounts payable and accrued expenses | 287 | 213 | 553 |
Capitalized stock-based compensation | 20 | 16 | 17 |
Common stock issued for business combinations | 1,727 | 0 | 0 |
Asset retirement obligations acquired | $ 65 | $ 2 | $ 4 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Commitments (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2021USD ($) | |
Water Services Agreement | |
Supply Commitment [Line Items] | |
Produced water disposal services term | 14 years |
Sand Supply Agreement | |
Supply Commitment [Line Items] | |
2022 | $ 18 |
2023 | 18 |
2024 | 18 |
2025 | 18 |
2026 | 5 |
Thereafter | 0 |
Total | 77 |
Transportation Commitments | |
Supply Commitment [Line Items] | |
2022 | 82 |
2023 | 85 |
2024 | 81 |
2025 | 86 |
2026 | 92 |
Thereafter | 452 |
Total | 878 |
Produced Water Disposal Commitments | |
Supply Commitment [Line Items] | |
2022 | 5 |
2023 | 5 |
2024 | 5 |
2025 | 5 |
2026 | 4 |
Thereafter | 27 |
Total | $ 51 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - Delivery Commitments (Details) | Dec. 31, 2021bbl |
Commitments and Contingencies Disclosure [Abstract] | |
2022 | 175,000 |
2023 | 175,000 |
2024 | 125,000 |
2025 | 125,000 |
2026 | 125,000 |
Thereafter | 325,000 |
Total | 1,050,000 |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES - Narrative (Details) - Equity Method Investments - Rattler LLC $ in Millions | Dec. 31, 2021USD ($) |
Supply Commitment [Line Items] | |
Future capital commitment | $ 28 |
Commitment to be funded in 2022 | 11 |
Commitment to be funded in 2023 | $ 17 |
SUBSEQUENT EVENTS - 2021 Divide
SUBSEQUENT EVENTS - 2021 Dividend Declaration (Details) - $ / shares | Feb. 18, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Subsequent Event [Line Items] | ||||
Dividends declared per share (in dollars per share) | $ 1.95 | $ 1.5250 | $ 0.9375 | |
Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Dividends declared per share (in dollars per share) | $ 0.60 |
SEGMENT INFORMATION - Additiona
SEGMENT INFORMATION - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2021segment | |
Segment Reporting [Abstract] | |
Number of business segments | 2 |
SEGMENT INFORMATION - Summary o
SEGMENT INFORMATION - Summary of Business Segments (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Segment Reporting Information [Line Items] | |||
Total revenues | $ 6,797,000,000 | $ 2,813,000,000 | $ 3,964,000,000 |
Depreciation, depletion, amortization and accretion | 1,275,000,000 | 1,311,000,000 | 1,454,000,000 |
Impairment of oil and natural gas properties | 0 | 6,021,000,000 | 790,000,000 |
Income (loss) from operations | 4,001,000,000 | (5,476,000,000) | 695,000,000 |
Interest expense, net | (199,000,000) | (197,000,000) | (172,000,000) |
Other income (expense), net | (895,000,000) | (103,000,000) | (161,000,000) |
Provision for (benefit from) income taxes | 631,000,000 | (1,104,000,000) | 47,000,000 |
Net income (loss) attributable to non-controlling interest | 94,000,000 | (155,000,000) | 75,000,000 |
Net income (loss) attributable to Diamondback Energy, Inc. | 2,182,000,000 | (4,517,000,000) | 240,000,000 |
Total assets | 22,898,000,000 | 17,619,000,000 | 23,531,000,000 |
Upstream | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 6,747,000,000 | 2,756,000,000 | 3,891,000,000 |
Midstream Operations | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 421,000,000 | 424,000,000 | 448,000,000 |
Operating Segments | Upstream | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 6,747,000,000 | 2,756,000,000 | 3,891,000,000 |
Depreciation, depletion, amortization and accretion | 1,219,000,000 | 1,257,000,000 | 1,411,000,000 |
Impairment of oil and natural gas properties | 6,021,000,000 | 790,000,000 | |
Income (loss) from operations | 3,879,000,000 | (5,562,000,000) | 790,000,000 |
Interest expense, net | (167,000,000) | (180,000,000) | (171,000,000) |
Other income (expense), net | (925,000,000) | (87,000,000) | (149,000,000) |
Provision for (benefit from) income taxes | 620,000,000 | (1,114,000,000) | 21,000,000 |
Net income (loss) attributable to non-controlling interest | 57,000,000 | (190,000,000) | 75,000,000 |
Net income (loss) attributable to Diamondback Energy, Inc. | 2,110,000,000 | (4,525,000,000) | 374,000,000 |
Total assets | 21,329,000,000 | 16,128,000,000 | 22,125,000,000 |
Operating Segments | Midstream Operations | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 50,000,000 | 57,000,000 | 73,000,000 |
Depreciation, depletion, amortization and accretion | 56,000,000 | 54,000,000 | 43,000,000 |
Impairment of oil and natural gas properties | 0 | 0 | |
Income (loss) from operations | 180,000,000 | 182,000,000 | 219,000,000 |
Interest expense, net | (32,000,000) | (17,000,000) | (1,000,000) |
Other income (expense), net | 38,000,000 | (10,000,000) | (6,000,000) |
Provision for (benefit from) income taxes | 11,000,000 | 10,000,000 | 26,000,000 |
Net income (loss) attributable to non-controlling interest | 37,000,000 | 35,000,000 | 91,000,000 |
Net income (loss) attributable to Diamondback Energy, Inc. | 138,000,000 | 110,000,000 | 95,000,000 |
Total assets | 1,942,000,000 | 1,809,000,000 | 1,636,000,000 |
Eliminations | |||
Segment Reporting Information [Line Items] | |||
Total revenues | (371,000,000) | (367,000,000) | (375,000,000) |
Depreciation, depletion, amortization and accretion | 0 | 0 | 0 |
Impairment of oil and natural gas properties | 0 | 0 | |
Income (loss) from operations | (58,000,000) | (96,000,000) | (314,000,000) |
Interest expense, net | 0 | 0 | 0 |
Other income (expense), net | (8,000,000) | (6,000,000) | (6,000,000) |
Provision for (benefit from) income taxes | 0 | 0 | 0 |
Net income (loss) attributable to non-controlling interest | 0 | 0 | (91,000,000) |
Net income (loss) attributable to Diamondback Energy, Inc. | (66,000,000) | (102,000,000) | (229,000,000) |
Total assets | $ (373,000,000) | $ (318,000,000) | $ (230,000,000) |
SUPPLEMENTAL INFORMATION ON O_3
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Oil and natural gas properties: | ||
Proved properties | $ 24,418 | $ 19,884 |
Unproved properties | 8,496 | 7,493 |
Total oil and natural gas properties | 32,914 | 27,377 |
Accumulated depletion | (5,434) | (4,237) |
Accumulated impairment | (7,954) | (7,954) |
Oil and natural gas properties, net | $ 19,526 | $ 15,186 |
SUPPLEMENTAL INFORMATION ON O_4
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Acquisition costs: | |||
Proved properties | $ 2,805 | $ 13 | $ 194 |
Unproved properties | 1,829 | 106 | 418 |
Development costs | 516 | 381 | 956 |
Exploration costs | 1,223 | 1,098 | 1,915 |
Total | $ 6,373 | $ 1,598 | $ 3,483 |
SUPPLEMENTAL INFORMATION ON O_5
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Oil, natural gas and natural gas liquid sales | $ 6,747 | $ 2,756 | $ 3,887 |
Production costs | (1,202) | (760) | (826) |
Depreciation, depletion, amortization and accretion | (1,211) | (1,249) | (1,405) |
Impairment | 0 | (6,021) | (790) |
Income tax benefit (expense) | (918) | 1,151 | (186) |
Results of operations | $ 3,416 | $ (4,123) | $ 680 |
SUPPLEMENTAL INFORMATION ON O_6
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Oil and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands | 12 Months Ended | |||
Dec. 31, 2021bblMcf | Dec. 31, 2020bblMcf | Dec. 31, 2019bblMcf | Dec. 31, 2018bblMcf | |
OIL | ||||
Proved Developed and Undeveloped Reserves (Volume) | ||||
Beginning of the period | 759,401 | 710,903 | 626,936 | |
Extensions and discoveries | 271,222 | 191,009 | 256,569 | |
Revisions of previous estimates | (160,570) | (78,244) | (84,789) | |
Purchase of reserves in place | 176,261 | 2,124 | 13,974 | |
Divestitures | (36,503) | (209) | (33,269) | |
Production | (81,522) | (66,182) | (68,518) | |
End of the period | 928,289 | 759,401 | 710,903 | |
Proved Developed Reserves (Volume) | 620,474 | 443,464 | 457,083 | 403,051 |
Proved Undeveloped Reserve (Volume) | 307,815 | 315,937 | 253,820 | 223,885 |
NATURAL GAS LIQUIDS | ||||
Proved Developed and Undeveloped Reserves (Volume) | ||||
Beginning of the period | 289,196 | 230,203 | 190,291 | |
Extensions and discoveries | 127,479 | 58,410 | 66,572 | |
Revisions of previous estimates | (6,685) | 21,927 | (8,166) | |
Purchase of reserves in place | 58,587 | 778 | 3,813 | |
Divestitures | (11,597) | (141) | (3,809) | |
Production | (27,246) | (21,981) | (18,498) | |
End of the period | 429,734 | 289,196 | 230,203 | |
Proved Developed Reserves (Volume) | 285,513 | 192,495 | 165,173 | 125,509 |
Proved Undeveloped Reserve (Volume) | 144,221 | 96,701 | 65,030 | 64,782 |
NATURAL GAS | ||||
Proved Developed and Undeveloped Reserves (Volume) | ||||
Beginning of the period | Mcf | 1,607,064 | 1,118,811 | 1,048,649 | |
Extensions and discoveries | Mcf | 720,125 | 316,035 | 318,874 | |
Revisions of previous estimates | Mcf | 195,302 | 300,160 | (149,657) | |
Purchase of reserves in place | Mcf | 302,770 | 3,512 | 19,830 | |
Divestitures | Mcf | (70,048) | (905) | (21,272) | |
Production | Mcf | (169,406) | (130,549) | (97,613) | |
End of the period | Mcf | 2,585,807 | 1,607,064 | 1,118,811 | |
Proved Developed Reserves (Volume) | Mcf | 1,770,688 | 1,085,035 | 824,760 | 705,084 |
Proved Undeveloped Reserve (Volume) | Mcf | 815,119 | 522,029 | 294,051 | 343,565 |
SUPPLEMENTAL INFORMATION ON O_7
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Narrative (Details) MBoe in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021USD ($)BoeMBoeswdWellwell | Dec. 31, 2020USD ($)BoeswdWell | Dec. 31, 2019USD ($)BoeswdWell | |
Oil and Gas, Delivery Commitment [Line Items] | |||
Extensions and discoveries (in MBOE) | 518,722,000 | 302,092,000 | 376,287,000 |
Oil and gas development well drilled net productive | swdWell | 470 | 682 | 283 |
Proved undeveloped reserves number of wells added | swdWell | 439 | 298 | 291 |
Percentage of extension volumes attributable to subsidiary | 6.00% | 8.00% | 5.00% |
Revision of previous estimate, (energy) | (134,705,000) | (6,290,000) | |
Change in corporate plan | 268,560,000 | 31,074,000 | |
Estimates increase due to higher commodity prices and improved well performance | 133,855,000 | ||
Increase due to purchase of reserves | 285,309,000 | 21,092,000 | |
Royalty purchases | 9,102,000 | ||
Increase due to acquisitions | 276,207,000 | ||
Divestitures of reserves | 59,775,000 | ||
Lower product pricing | 54,645,000 | ||
Reduction in LOE | 23,066,000 | ||
Total negative pricing revision | 31,579,000 | ||
Performance revisions | 56,362,000 | ||
Decrease due to inventory refinement and lower realized price | (117,898,000) | ||
Purchase of working interest in Reserves | 10,939,000 | ||
Proved undeveloped reserves (energy) | 587,889,000 | 499,643,000 | |
Proved undeveloped reserves, increase (energy) | 88,246,000 | ||
Extensions and discoveries, working interest (in MBOE) | MBoe | 416,327 | ||
Number of horizontal wells developed, working interest gross | well | 439 | ||
Number of horizontal wells developed, working interest | well | 383 | ||
Proved undeveloped reserves extensions and discoveries mineral interest | MBoe | 24,700 | ||
Number of horizontal wells developed, mineral interest | well | 336 | ||
Undeveloped reserves transferred to developed | 172,526,000 | ||
Number of horizontal wells developed working interest gross | well | 154 | ||
Number of horizontal wells developed working interest net | well | 142 | ||
Number of horizontal wells developed mineral interest gross | well | 127 | ||
Number of horizontal wells developed working and mineral interest | well | 106 | ||
Revisions | (243,268,000) | ||
Revisions from PUD reclassifications due to lower benchmark commodity prices | 260,494,000 | ||
Revisions from PUD reclassifications due to refinement | 17,226,000 | ||
Proved undeveloped reserves, planned development period | 5 years | ||
Capital expenditures towards development of proved undeveloped reserves | $ | $ 516 | $ 381 | $ 956 |
QEP and Guidon | |||
Oil and Gas, Delivery Commitment [Line Items] | |||
Increase due to purchase of reserves | 63,013,000 | ||
Increase due to acquisitions | 59,023,000 | ||
Midland Basin | |||
Oil and Gas, Delivery Commitment [Line Items] | |||
Number of horizontal wells developed working interest | well | 409 | ||
Delaware Basin | |||
Oil and Gas, Delivery Commitment [Line Items] | |||
Number of horizontal wells developed working interest | well | 30 | ||
Viper Energy Partners LP | |||
Oil and Gas, Delivery Commitment [Line Items] | |||
Oil and gas development well drilled net productive | swdWell | 345 | ||
Royalty purchases | 3,990,000 | 10,153,000 |
SUPPLEMENTAL INFORMATION ON O_8
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Proved Undeveloped Reserves (Details) Boe in Thousands | 12 Months Ended |
Dec. 31, 2021Boe | |
Proved Undeveloped Reserves (Energy) | |
Beginning proved undeveloped reserves at December 31, 2020 | 499,643 |
Undeveloped reserves transferred to developed | (172,526) |
Revisions | (243,268) |
Purchases | 63,013 |
Divestitures | 0 |
Extensions and discoveries | 441,027 |
Ending proved undeveloped reserves at December 31, 2021 | 587,889 |
SUPPLEMENTAL INFORMATION ON O_9
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows - Proved Crude Oil and Natural Gas Reserves (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract] | ||||
Future cash inflows | $ 77,085 | $ 32,173 | $ 40,681 | |
Future development costs | (4,243) | (3,585) | (3,809) | |
Future production costs | (19,123) | (10,763) | (9,319) | |
Future production taxes | (5,572) | (2,354) | (2,905) | |
Future income tax expenses | (7,237) | (727) | (2,635) | |
Future net cash flows | 40,910 | 14,744 | 22,013 | |
10% discount to reflect timing of cash flows | (22,193) | (7,986) | (11,829) | |
Standardized measure of discounted future net cash flows | 18,717 | 6,758 | 10,184 | $ 11,676 |
Oil and Gas, Delivery Commitment [Line Items] | ||||
Standardized measure of discounted future net cash flows | $ 18,717 | 6,758 | 10,184 | $ 11,676 |
Viper Energy Partners LP | ||||
Oil and Gas, Delivery Commitment [Line Items] | ||||
Noncontrolling interest, ownership percentage | 54.00% | |||
Viper Energy Partners LP | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract] | ||||
Standardized measure of discounted future net cash flows | $ 2,100 | 1,000 | 1,300 | |
Oil and Gas, Delivery Commitment [Line Items] | ||||
Standardized measure of discounted future net cash flows | $ 2,100 | $ 1,000 | $ 1,300 |
SUPPLEMENTAL INFORMATION ON _10
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Average First Day of the Month Price for Oil, Natural Gas & Natural Gas Liquids (Details) | 12 Months Ended | ||
Dec. 31, 2021$ / bbl$ / Mcf | Dec. 31, 2020$ / Mcf$ / bbl | Dec. 31, 2019$ / Mcf$ / bbl | |
OIL | |||
Oil and Gas, Delivery Commitment [Line Items] | |||
Average sales prices (dollars per unit) | 64.78 | 38.06 | 51.88 |
NATURAL GAS | |||
Oil and Gas, Delivery Commitment [Line Items] | |||
Average sales prices (dollars per unit) | $ / Mcf | 2.61 | 0.09 | 0.18 |
NATURAL GAS LIQUIDS | |||
Oil and Gas, Delivery Commitment [Line Items] | |||
Average sales prices (dollars per unit) | 23.71 | 10.83 | 15.65 |
SUPPLEMENTAL INFORMATION ON _11
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | |||
Standardized measure of discounted future net cash flows at the beginning of the period | $ 6,758 | $ 10,184 | $ 11,676 |
Sales of oil and natural gas, net of production costs | (5,757) | (2,225) | (3,334) |
Acquisitions of reserves | 1,914 | 30 | 309 |
Divestitures of reserves | (275) | (4) | (500) |
Extensions and discoveries, net of future development costs | 6,298 | 1,514 | 4,004 |
Previously estimated development costs incurred during the period | 548 | 704 | 120 |
Net changes in prices and production costs | 10,748 | (5,273) | 831 |
Changes in estimated future development costs | (19) | 526 | (3,190) |
Revisions of previous quantity estimates | 719 | (462) | (1,242) |
Accretion of discount | 703 | 1,126 | 1,344 |
Net change in income taxes | (2,841) | 807 | 693 |
Net changes in timing of production and other | (79) | (169) | (527) |
Standardized measure of discounted future net cash flows at the end of the period | $ 18,717 | $ 6,758 | $ 10,184 |