0001539838-22-000008 | 10-K | XBRL Viewer

Changes in operating assets and liabilities:

47,000,000

30,000,000

8,000,000

Accounts receivable

(196,000,000)

217,000,000

(187,000,000)

Income tax receivable

152,000,000

(62,000,000)

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

Net cash provided by (used in) operating activities

(47,000,000)

1,000,000

(15,000,000)

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

Net cash provided by (used in) investing activities

45,000,000

(58,000,000)

(6,000,000)

(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

(41,000,000)

Proceeds from public offerings

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)

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

Net cash provided by (used in) financing activities

(36,000,000)

(19,000,000)

(22,000,000)

(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 BASIS OF PRESENTATION	12 Months Ended
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION	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 ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

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 to 30 years.

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.

The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.

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

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.

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
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Business Combinations And Divestitures [Abstract]

ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2021

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	12 Months Ended
VIPER ENERGY PARTNERS LP	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 MIDSTREAM LP 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	12 Months Ended
RATTLER MIDSTREAM LP	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 MIDSTREAM LP 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

12 Months Ended

Dec. 31, 2021

Real Estate [Abstract]

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

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

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

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:


	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

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.

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

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

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

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-URI http://asc.fasb.org/topic&trid=2208564

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (h)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
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STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

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.

(2) For the year ended December 31, 2020, there were 696,223 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive due to recording a net loss.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Share-based Payment Arrangement [Abstract]

EQUITY-BASED COMPENSATION

12 Months Ended

Dec. 31, 2021

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 Units	Weighted Average Grant-Date Fair Value
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 Units	Weighted Average Grant-Date Fair Value
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

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

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

is highly uncertain, the Company does not expect the change in unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2021 and 2020, there was less than $0.2 million of interest and no penalties related to each period associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (b)
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

12 Months Ended

Dec. 31, 2021

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

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

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

The carrying amount of cash and cash equivalents, receivables, funds held in escrow, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Supplemental Cash Flow Information Disclosure [Abstract]

SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS

12 Months Ended

Dec. 31, 2021

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

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

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	12 Months Ended
SUBSEQUENT EVENTS	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

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

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

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Oil and Gas Exploration and Production Industries Disclosures [Abstract]

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

12 Months Ended

Dec. 31, 2021

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 (MBbls)	Natural Gas Liquids (MBbls)	Natural Gas (MMcf)
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 ACCOUNTING POLICIES (Policies)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	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. 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 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 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.
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. 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.
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 to 30 years.
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. 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.
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 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	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.
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. The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.
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 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 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 (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)

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)

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 (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 (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

Income (loss) and distributions from Rattler’s equity method investees were not material for the years ended December 31, 2021, 2020 or 2019.

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.

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

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

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Schedule of Change in Ownership of Consolidated Subsidiaries

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

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

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

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 Units	Weighted Average Grant-Date Fair Value
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 Units	Weighted Average Grant-Date Fair Value
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)

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)

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.


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.

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

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Schedule of Fair Value Measurement Information For Financial Instruments Measured on a Recurring Basis

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]


	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


	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


	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 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 (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

(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)

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 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


	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 (MBbls)	Natural Gas Liquids (MBbls)	Natural Gas (MMcf)
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

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

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

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

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 ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) $ / Boe	Dec. 31, 2020 USD ($) $ / Boe	Dec. 31, 2019 USD ($) $ / 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 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 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 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 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

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

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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 - Narrative (Details) shares in Thousands												12 Months Ended
	Dec. 01, 2021 USD ($)	Nov. 01, 2021 USD ($)	Oct. 21, 2021 USD ($) a	Oct. 05, 2021 USD ($) MMcf / d property	Oct. 01, 2021 USD ($) a shares	Mar. 31, 2021 USD ($)	Feb. 26, 2021 USD ($) a well shares	Dec. 21, 2020 USD ($)	Jul. 29, 2019 USD ($) shares	Jul. 01, 2019 USD ($)	May 23, 2019 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Jun. 03, 2021 a	Mar. 17, 2021 USD ($) 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
Proceeds from divestiture of certain conventional and non-core assets									$ 497,000,000
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 \| 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 - 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 - Schedule of Purchase Price Allocation (Details) - Guidon Operating LLC $ in Millions	Dec. 21, 2020 USD ($)
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 - Schedule Of Business Acquisition Consideration Paid (Details) - QEP $ / shares in Units, $ in Millions	Mar. 17, 2021 USD ($) $ / shares shares
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 - 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 - 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 - 2020 Activity (Details) - Mineral Interests In Permian Basin $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) 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 - 2019 Activity (Details)	Nov. 01, 2021 USD ($)	Jul. 01, 2019 USD ($) a	May 23, 2019 USD ($) 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 - 2019 Drop Down Transaction (Details) shares in Millions, $ in Millions	Nov. 01, 2021 USD ($)	Jul. 29, 2019 USD ($) a shares
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]
Proceeds from divestiture of certain conventional and non-core assets		$ 497
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 \| 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 - 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	$ 150,000,000		$ 100,000,000	$ 100,000,000
Stock repurchase program amount repurchased		48,000,000
Stock repurchase remaining authorized amount		$ 88,000,000
Follow-on Public Offering
Noncontrolling Interest [Line Items]
Number of common units sold (in shares)	10,925,000	0	0
Consideration received on transaction	$ 341,000,000
Over-Allotment Option
Noncontrolling Interest [Line Items]
Number of common units sold (in shares)	1,425,000
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) - USD ($)			12 Months Ended
RATTLER MIDSTREAM LP (Details) - USD ($)	Dec. 21, 2021	May 28, 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]
Limited partners capital contribution		$ 1,000,000
General partners cash contribution		1,000,000
Distribution to affiliates		$ 727,000,000
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
Class B Units
Noncontrolling Interest [Line Items]
Limited partners' capital account, units issued (in Shares)		107,815,152
Common Stock
Noncontrolling Interest [Line Items]
Stock repurchase program authorized amount						$ 150,000,000	$ 150,000,000		$ 100,000,000	$ 100,000,000
Stock repurchase program amount repurchased			48,000,000
Stock repurchase remaining authorized amount			88,000,000
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
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 MIdstream LP
Noncontrolling Interest [Line Items]
Ownership percentage		29.00%	74.00%
Limited partners ownership percentage	100.00%	71.00%

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 - 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 - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
PROPERTY AND EQUIPMENT - Narrative (Details) - USD ($)	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 (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 - 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%
EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Ownership Interest	10.00%
Equity method investments	$ 107	$ 121
Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	10.00%
Equity method investments	$ 121	130
Wink to Webster Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	4.00%
Equity method investments	$ 86	83
OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	60.00%
Equity method investments	$ 188	194
Amarillo Rattler, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	0.00%
Equity method investments	$ 0	5
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)	1 Months Ended		12 Months Ended
DEBT - Long-term Debt (Details)	Aug. 31, 2021 USD ($)	Jun. 30, 2021 USD ($) derivative instrument	Dec. 31, 2021 USD ($) well	Mar. 24, 2021	Mar. 17, 2021	Dec. 31, 2020 USD ($)
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 \| 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%
Long-term debt, gross			$ 480,000,000			480,000,000
Rattler revolving credit facility \| 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%
Long-term debt, gross			$ 500,000,000			$ 500,000,000

DEBT - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2021 USD ($)
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 Restated Credit Facility (Details)		12 Months Ended
	Jun. 02, 2021 USD ($) extension	Dec. 31, 2021 USD ($) letter	Dec. 31, 2020 USD ($)	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 (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 Notes (Details) - USD ($)			1 Months Ended			12 Months Ended
DEBT - 2021 Redemptions of Notes (Details) - USD ($)	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 (Details)		12 Months Ended
DEBT - Viper's Credit Agreement (Details)	Jun. 02, 2021 redetermination	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019	Nov. 15, 2021 USD ($)
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		500,000,000			$ 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 \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 304,000,000	$ 84,000,000
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		2.50
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%

DEBT - Financial Covenant Table (Details)	12 Months Ended
DEBT - Financial Covenant Table (Details)	Dec. 31, 2021
Maximum \| Rattler revolving credit facility \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Consolidated total leverage ratio	5.00
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	4.0
Ratio of secured debt to EBITDAX, as defined in the credit agreement	2.50
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	1.0

DEBT - Rattler's Credit Agreement (Details) - USD ($)			12 Months Ended
DEBT - Rattler's Credit Agreement (Details) - USD ($)	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
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%
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%

DEBT - Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
DEBT - Interest Expense (Details) - USD ($) $ in Millions	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 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 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)	329	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	329	(33)
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

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

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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 - 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 - 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 - Restricted Stock Units (Details) - Equity Plan - Restricted Stock Units (RSUs)	12 Months Ended
	Dec. 31, 2021 $ / shares shares
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 - 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 - Performance-Based Restricted Stock Units - Narrative (Details) - Performance Shares - Equity Plan $ in Millions		1 Months Ended			12 Months Ended
	Dec. 31, 2021 USD ($)	Mar. 31, 2021 shares	Mar. 31, 2020 shares	Mar. 31, 2019 installment shares	Dec. 31, 2021 USD ($) 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 - 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 - Rattler Long-Term Incentive Plan - Narrative (Details) - Rattler Midstream LP Long-Term Incentive Plan $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) distributionRight shares	May 22, 2019 shares
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 - Rattler Long-Term Incentive Plan (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan	12 Months Ended
	Dec. 31, 2021 $ / shares shares
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 (Details) - USD ($)		3 Months Ended		12 Months Ended
INCOME TAXES - Narrative (Details) - USD ($)	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				(169,000,000)	(166,000,000)
Deferred tax liability includes deferred tax asset				6,000,000	150,000,000
Operating loss carryforwards				108,000,000
Net operating loss and carryforwards				23,000,000	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%
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 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

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

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

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.