0001539838-24-000019 | 10-K | XBRL Viewer

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DEBT - Issuances of Notes (Details) - USD ($)					12 Months Ended
DEBT - Issuances of Notes (Details) - USD ($)	Oct. 19, 2023	Dec. 13, 2022	Oct. 28, 2022	Mar. 17, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Proceeds from senior notes					$ 400,000,000	$ 2,500,000,000	$ 2,200,000,000
Viper 7.375% Senior Notes due 2031
Debt Instrument [Line Items]
Stated interest rate	7.375%
Proceeds from senior notes	$ 394,000,000
Viper 7.375% Senior Notes due 2031 \| Viper
Debt Instrument [Line Items]
Aggregate principal amount	$ 400,000,000
Viper 7.375% Senior Notes due 2031 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate					7.375%
6.250% Senior Notes due 2053 \| Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount		$ 650,000,000
Stated interest rate		6.25%			6.25%
Proceeds from debt		$ 643,000,000
Underwriting discounts and offering expenses		$ 7,000,000
6.250% Senior Notes due 2033 \| Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount			$ 1,100,000,000
Stated interest rate			6.25%		6.25%
Proceeds from senior notes			$ 1,100,000,000
Underwriting discounts and offering expenses			$ 15,000,000
4.250% Senior Notes due 2052 \| Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount				$ 750,000,000
Stated interest rate				4.25%	4.25%
Proceeds from debt				$ 739,000,000
Underwriting discounts and offering expenses				$ 11,000,000

DERIVATIVES - Interest Rate Swaps (Details) $ in Millions	12 Months Ended
DERIVATIVES - Interest Rate Swaps (Details) $ in Millions	Dec. 31, 2023 USD ($) instrument	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($) instrument
Offsetting Assets [Line Items]
Number of agreements \| instrument					2
Net gain on sale of interest rate swaps and treasury locks	$ (110)	$ (850)	$ (1,225)
Interest Rate Contract
Offsetting Assets [Line Items]
Notional amount					$ 600
Net gain on sale of interest rate swaps and treasury locks	$ (49)	$ (1)	$ 80
Interest Rate Contract \| Designated as Hedging Instrument \| SOFR
Offsetting Assets [Line Items]
Average variable interest rate					2.1865%
Interest rate swaps
Offsetting Assets [Line Items]
Number of agreements \| instrument	2
Interest rate swaps \| Senior Notes Due 2029 \| Designated as Hedging Instrument
Offsetting Assets [Line Items]
Fair value hedges					$ 1,200
Derivative, fixed interest rate					3.50%
Discontinuation of fair value hedge				$ 135

REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Other operating income	$ 73	$ 77	$ 50
Total revenues	8,412	9,643	6,797
Aggregate Revenues
Disaggregation of Revenue [Line Items]
Total revenues	8,401	9,635	6,792
Total oil, natural gas and natural gas liquid revenues
Disaggregation of Revenue [Line Items]
Revenues	8,228	9,566	6,747
Total oil, natural gas and natural gas liquid revenues \| Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	6,422	6,823	4,288
Total oil, natural gas and natural gas liquid revenues \| Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	1,799	2,726	2,127
Total oil, natural gas and natural gas liquid revenues \| Other
Disaggregation of Revenue [Line Items]
Revenues	7	17	332
Oil sales
Disaggregation of Revenue [Line Items]
Revenues	7,279	7,660	5,396
Oil sales \| Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	5,746	5,541	3,468
Oil sales \| Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	1,527	2,107	1,663
Oil sales \| Other
Disaggregation of Revenue [Line Items]
Revenues	6	12	265
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues	262	858	569
Natural gas sales \| Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	176	563	327
Natural gas sales \| Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	85	292	215
Natural gas sales \| Other
Disaggregation of Revenue [Line Items]
Revenues	1	3	27
Natural gas liquid sales
Disaggregation of Revenue [Line Items]
Revenues	687	1,048	782
Natural gas liquid sales \| Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	500	719	493
Natural gas liquid sales \| Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	187	327	249
Natural gas liquid sales \| Other
Disaggregation of Revenue [Line Items]
Revenues	0	2	40
Sales of purchased oil
Disaggregation of Revenue [Line Items]
Revenues	111	0	0
Midstream and marketing services
Disaggregation of Revenue [Line Items]
Other operating income	$ 62	$ 69	$ 45

ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2023

Business Combinations And Divestitures [Abstract]

ACQUISITIONS AND DIVESTITURES

2023 Activity

Acquisitions

GRP Acquisition

On November 1, 2023, Viper and Viper LLC acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP and affiliates of Warwick Capital Partners and GRP Energy Capital (collectively, “GRP”), pursuant to a definitive purchase and sale agreement for approximately 9.02 million Viper common units and $760 million in cash, including transaction costs and subject to customary post-closing

adjustments (the “GRP Acquisition”). The mineral and royalty interests acquired in the GRP Acquisition represent 4,600 net royalty acres in the Permian Basin, plus an additional 2,700 net royalty acres in other major basins. The cash consideration for the GRP Acquisition was funded through a combination of cash on hand and held in escrow, borrowings under the Viper credit agreement, proceeds from the Viper 2031 Notes (as defined in Note 8—Debt) and proceeds from the $200 million common unit issuance to the Company.

Deep Blue Formation and Divestiture of Deep Blue Water Assets

On September 1, 2023, the Company closed on a joint venture agreement with Five Point Energy LLC (“Five Point”) to form Deep Blue Midland Basin LLC (“Deep Blue”). At closing, the Company contributed certain treated water, fresh water and saltwater disposal assets (the “Deep Blue Water Assets”) with a net carrying value of $692 million and Five Point contributed $251 million in cash, subject to certain customary post-closing adjustments, to Deep Blue. In exchange for these contributions, Deep Blue issued the Company a one-time cash distribution of approximately $516 million and issued to the Company a 30% equity ownership and voting interest, and issued to Five Point a 70% equity ownership and voting interest.

Under a separate agreement with Deep Blue, the Company is continuing to operate the Deep Blue Water Assets on a short-term basis before transferring operations to Deep Blue, which is anticipated to happen in 2024. Contingent upon the successful transfer of operations, the Company will receive approximately $47 million in cash to be contributed by Five Point in 2024. This contingent consideration does not meet the criteria to be accounted for as a derivative. As such, at December 31, 2023, approximately $43 million has been recorded as a receivable in the consolidated balance sheet for the fair value of the additional consideration to be received when operation of the Deep Blue Water Assets transfers to Deep Blue.

The Company recorded its 30% equity interest in Deep Blue at fair value based on the cash consideration contributed by Five Point to Deep Blue in exchange for its 70% equity ownership and the estimated fair value of contingent consideration to be contributed by Five Point in future years. The Company’s equity method investment in Deep Blue had an initial fair value of $126 million. The Company’s proportionate share of the income or loss from Deep Blue will be recognized on a two-month lag. For the year ended December 31, 2023, the Company recognized a $12 million loss on the sale of its Deep Blue Water Assets, which is included in the caption “Other operating expenses” in the consolidated statement of operations. The majority of measurements utilized to determine the fair value amounts reported above relating to this transaction are based on inputs that are not observable in the market and are therefore considered Level 3 inputs in the fair value hierarchy.

The Company and Five Point currently anticipate collectively contributing $500 million in follow-on capital to fund future growth projects and acquisitions.

As part of the transaction, the Company also entered into a 15-year dedication with Deep Blue for its produced water and supply water within a 12-county area of mutual interest in the Midland Basin. Fees paid to Deep Blue for produced water and supply water services and fees received from Deep Blue for operating services provided by the Company during the year ended December 31, 2023 were insignificant.

Lario Acquisition

On January 31, 2023, the Company closed on its acquisition of all leasehold interests and related assets of Lario Permian, LLC, a wholly owned subsidiary of Lario Oil and Gas Company, and certain associated sellers (collectively “Lario”). The acquisition included approximately 25,000 gross (16,000 net) acres in the Midland Basin and certain related oil and gas assets (the “Lario Acquisition”), in exchange for 4.33 million shares of the Company’s common stock and $814 million in cash, including certain customary post-closing adjustments. Approximately $113 million of the cash consideration was deposited in an indemnity holdback escrow account at closing to be distributed upon satisfactory settlement of any potential title defects on the acquired properties. The cash portion of the consideration for the Lario Acquisition was funded through a combination of cash on hand, a portion of the net proceeds from the Company’s offering of 6.250% Senior Notes due 2053 and borrowings under the Company’s revolving credit facility.

The following table presents the acquisition consideration paid in the Lario Acquisition (in millions, except per share data, shares in thousands):


Consideration:
Shares of Diamondback common stock issued at closing	4,330
Closing price per share of Diamondback common stock on the closing date	$	146.12
Fair value of Diamondback common stock issued	$	633
Cash consideration	814
Total consideration (including fair value of Diamondback common stock issued)	$	1,447

Purchase Price Allocation

The Lario 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 Lario Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The purchase price allocation was completed in December 2023, with no further adjustments to the previously reported fair values of assets acquired and liabilities assumed.

The following table sets forth the Company’s purchase price allocation (in millions):








Total consideration	$	1,447

Fair value of liabilities assumed:
Other long-term liabilities	37

Fair value of assets acquired:
Oil and natural gas properties	1,460
Inventories	2
Other property, equipment and land	22
Amount attributable to assets acquired	1,484
Net assets acquired and liabilities assumed	$	1,447

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, vehicles and a field office were 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 and were included in the Company’s consolidated balance sheets under the caption “Other property, equipment and land.” 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 in the fair value hierarchy.

With the completion of the Lario Acquisition, the Company acquired proved properties of $924 million and unproved properties of $536 million. The results of operations attributable to the Lario Acquisition since the acquisition date have been included in the consolidated statements of operations and include $488 million of total revenue and $200 million of net income for the year ended December 31, 2023.

Divestitures

OMOG Divestiture

On July 28, 2023, the Company divested its 43% limited liability company interest in OMOG JV LLC (“OMOG”) for $225 million in cash received at closing. This divestiture resulted in a gain on the sale of equity method investments of approximately $35 million for the year ended December 31, 2023, which is included in the caption “Other income (expense), net” in the consolidated statement of operations. The Company used its net proceeds from this transaction for debt reduction and other general corporate purposes.

Non-Core Assets Divestitures

On April 28, 2023, the Company divested non-core assets to an unrelated third-party buyer consisting of approximately 19,000 net acres in Glasscock County, TX for net cash proceeds at closing of $269 million, including customary post-closing adjustments. The Company used its net proceeds from this transaction for debt reduction and other general corporate purposes.

On March 31, 2023, the Company divested non-core assets consisting of approximately 4,900 net acres in Ward and Winkler counties to unrelated third-party buyers for $72 million in net cash proceeds, including customary post-closing adjustments.

The divestitures of non-core oil and gas assets 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.

Gray Oak Divestiture

On January 9, 2023, the Company divested its 10% non-operating equity investment in Gray Oak Pipeline, LLC (“Gray Oak”) for $172 million in net cash proceeds and recorded a gain on the sale of equity method investments of approximately $53 million in the first quarter of 2023 that is included in the caption “Other income (expense), net” on the consolidated statement of operations for the year ended December 31, 2023.

2022 Activity

Acquisitions

FireBird Energy LLC Acquisition

On November 30, 2022, the Company closed on its acquisition of all leasehold interests and related assets of FireBird Energy LLC, which included approximately 75,000 gross (68,000 net) acres in the Midland Basin and certain related oil and gas assets, in exchange for 5.92 million shares of the Company’s common stock and $787 million in cash, including certain customary post-closing adjustments. Approximately $125 million of the cash consideration was deposited in an indemnity holdback escrow account at closing to be distributed upon satisfactory settlement of any potential title defects on the acquired properties. The cash portion of the consideration for the FireBird Acquisition was funded through a combination of cash on hand and borrowings under the Company’s revolving credit facility. As a result of the FireBird Acquisition, the Company added approximately 854 gross producing wells.

The following table presents the acquisition consideration paid in the FireBird Acquisition (in millions, except per share data, shares in thousands):


Consideration:
Shares of Diamondback common stock issued at closing	5,921
Closing price per share of Diamondback common stock on the closing date	$	148.02
Fair value of Diamondback common stock issued	$	876
Cash consideration	787
Total consideration (including fair value of Diamondback common stock issued)	$	1,663

Purchase Price Allocation

The FireBird 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 FireBird Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The purchase price allocation was completed during November 2023 with no further adjustments to the previously reported fair values of assets acquired and liabilities assumed.

The following table sets forth the Company’s purchase price allocation (in millions):








Total consideration	$	1,663

Fair value of liabilities assumed:
Other long-term liabilities	10

Fair value of assets acquired:
Oil and natural gas properties	1,598
Inventories	3
Other property, equipment and land	72
Amount attributable to assets acquired	1,673
Net assets acquired and liabilities assumed	$	1,663

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 and was included in the Company’s consolidated balance sheets under the caption “Other property, equipment and land.” 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 FireBird Acquisition, the Company acquired proved properties of $648 million and unproved properties of $950 million. The results of operations attributable to the FireBird Acquisition from the acquisition date through December 31, 2022 have been included in the consolidated statement of operations and include $46 million of total revenue and $28 million of net income.

Delaware Basin Acquisition

On January 18, 2022, the Company acquired, from an unrelated third-party seller, approximately 6,200 net acres in the Delaware Basin for $232 million in cash, including customary post-closing adjustments. The acquisition was funded through cash on hand.

Other 2022 Acquisitions

Additionally during the year ended December 31, 2022, the Company acquired, from unrelated third-party sellers, approximately 4,000 net acres and over 200 gross wells in the Permian Basin for an aggregate purchase price of approximately $220 million in cash, including customary closing adjustments. The acquisitions were funded through cash on hand.

Divestitures

Non-Core Assets Divestitures

In October 2022, the Company completed the divestiture of non-core Delaware Basin acreage consisting of approximately 3,272 net acres, with net production of approximately 550 BO/d (800 BOE/d) for $155 million of net proceeds. The Company used the net proceeds from this transaction towards debt reduction.

2021 Activity

Acquisitions

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 included 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 the consideration for the Guidon Acquisition 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 purchase price allocation was completed in the first quarter of 2022.

The following table sets forth the Company’s 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 natural 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 from the acquisition date through December 31, 2021 have been included in the consolidated statements of operations for the year ended December 31, 2021, and include $345 million of total revenue and $170 million of net income.

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.

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 allocation of the total purchase price for the acquisition of QEP to the identifiable assets acquired and the liabilities at the acquisition date. The purchase price allocation was completed in the first quarter of 2022.

The following table sets forth the Company’s 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	2,922
Other property, equipment and land	16
Deferred income taxes	39
Other assets	106
Amount attributable to assets acquired	3,294
Net assets acquired and liabilities assumed	$	987

The purchase price allocation above was 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 were 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, 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. 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 $733 million, primarily in the Midland Basin and the Williston Basin. In October 2021, the Company completed the divestiture of the Williston Basin properties, acquired as part of the QEP Merger and consisting of approximately 95,000 net acres, to Oasis Petroleum Inc. for net cash proceeds of approximately $586 million, after customary closing adjustments. See “—Williston Basin Divestiture” below.

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.

Viper’s Swallowtail Acquisition

On October 1, 2021, Viper acquired certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC 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 the consideration for the Swallowtail Acquisition 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.

Divestitures

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 $164 million, in a drop down transaction (the “Drop Down”). The midstream assets consisted 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 $164 million. The Company and Rattler also mutually amended 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.

Rattler’s Gas Gathering Divestiture

On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos for aggregate total consideration of $84 million, after customary closing adjustments.

Pro Forma Financial Information (Unaudited)

The following unaudited summary pro forma financial information for the years ended December 31, 2023, 2022 and 2021 has been prepared to give effect to (i) the QEP Merger and the Guidon Acquisition as if they had occurred on January 1, 2020, (ii) the FireBird Acquisition as if it had occurred on January 1, 2021, and (iii) the Lario Acquisition as if it had occurred on January 1, 2022. 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 as consideration for Firebird, Lario and 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 of (i) $8 million and $3 million for the Lario Acquisition and the FireBird Acquisition during the year ended December 31, 2023, respectively, (ii) $2 million for the FireBird Acquisition during the year ended December 31, 2022, (iii) $78 million for the QEP Merger and the Guidon Acquisition during the year ended December 31, 2021, and (iv) $31 million of costs incurred by QEP 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, the Guidon Acquisition, the FireBird Acquisition and the Lario 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,
		2023		2022		2021
		(In millions, except per share amounts)
Revenues		$	8,457	$	10,542	$	7,198
Income (loss) from operations		$	4,607	$	7,071	$	4,193
Net income (loss)		$	3,175	$	4,834	$	2,148
Basic earnings per common share		$	17.48	$	25.74	$	11.40
Diluted earnings per common share		$	17.48	$	25.74	$	11.40

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Other Property, Equipment and Land (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Real Estate [Line Items]
Buildings	$ 98	$ 96
Tenant improvements	5	5
Land	1	1
Land improvements	1	1
Total real estate assets	105	103
Less: accumulated depreciation and amortization	(23)	(20)
Total investment in land and buildings, net	$ 82	$ 83
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	13 years
Maximum \| Land improvements
Real Estate [Line Items]
Estimated Useful Lives	15 years

FAIR VALUE MEASUREMENTS - Recurring Measurements (Details) - Fair Value, Recurring - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Noncurrent Assets
Assets:
Gross Amounts Offset in Balance Sheet	$ 0
Investment	5
Commodity derivative instruments \| Current Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	88	$ 197
Gross Amounts Offset in Balance Sheet	(71)	(65)
Net Fair Value Presented in Balance Sheet	17	132
Commodity derivative instruments \| Noncurrent Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	8	62
Gross Amounts Offset in Balance Sheet	(7)	(39)
Net Fair Value Presented in Balance Sheet	1	23
Commodity derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	111	67
Gross Amounts Offset in Balance Sheet	(71)	(65)
Net Fair Value Presented in Balance Sheet	40	2
Commodity derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	12	39
Gross Amounts Offset in Balance Sheet	(7)	(39)
Net Fair Value Presented in Balance Sheet	5	0
Interest rate swaps \| Current Liabilities
Liabilities:
Total Gross Fair Value	46	45
Gross Amounts Offset in Balance Sheet	0	0
Net Fair Value Presented in Balance Sheet	46	45
Interest rate swaps \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	117	148
Gross Amounts Offset in Balance Sheet	0	0
Net Fair Value Presented in Balance Sheet	117	148
Level 1 \| Noncurrent Assets
Assets:
Investment	5
Level 1 \| Commodity derivative instruments \| Current Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	0	0
Level 1 \| Commodity derivative instruments \| Noncurrent Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	0	0
Level 1 \| Commodity derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 1 \| Commodity derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 1 \| Interest rate swaps \| Current Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 1 \| Interest rate swaps \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 2 \| Noncurrent Assets
Assets:
Investment	0
Level 2 \| Commodity derivative instruments \| Current Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	88	197
Level 2 \| Commodity derivative instruments \| Noncurrent Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	8	62
Level 2 \| Commodity derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	111	67
Level 2 \| Commodity derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	12	39
Level 2 \| Interest rate swaps \| Current Liabilities
Liabilities:
Total Gross Fair Value	46	45
Level 2 \| Interest rate swaps \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	117	148
Level 3 \| Noncurrent Assets
Assets:
Investment	0
Level 3 \| Commodity derivative instruments \| Current Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	0	0
Level 3 \| Commodity derivative instruments \| Noncurrent Assets
Assets:
Derivative Asset, Fair Value, Gross Asset	0	0
Level 3 \| Commodity derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 3 \| Commodity derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 3 \| Interest rate swaps \| Current Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 3 \| Interest rate swaps \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	$ 0	$ 0

EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Activity (Details) - Performance Shares - Equity Plan - $ / shares	1 Months Ended				12 Months Ended
	Jul. 31, 2023	Mar. 31, 2023	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value Assumptions
Grant-date fair value (in dollars per share)	$ 222.09	$ 259.52				$ 237.13	$ 131.06
Risk-free rate	4.70%	4.64%				1.44%	15.00%
Company volatility	47.20%	46.90%				72.10%	69.60%
Performance Restricted Stock Units
Unvested, beginning balance (in shares)					347,881
Granted (in shares)	1,858	126,347	126,905	198,454	361,268
Vested (in shares)					(388,436)
Forfeited (in shares)					(42,657)
Unvested, ending balance (in shares)					278,056	347,881
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in dollars per share)					$ 168.48
Granted (in dollars per share)					258.98
Vested (in dollars per share)					134.64
Forfeited (in dollars per share)					144.48
Unvested, ending balance (in dollars per share)					$ 234.80	$ 168.48
Maximum units could be awarded (in shares)					645,703

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Derivative liability payable	$ 13	$ 21
Lease operating expenses payable	160	131
Ad valorem taxes payable	129	108
Accrued compensation	38	35
Interest payable	73	49
Midstream operating expenses payable	8	15
Other	54	40
Total other accrued liabilities	$ 475	$ 399

EQUITY-BASED COMPENSATION - Narratives (Details) - Equity Plan shares in Millions	Dec. 31, 2023 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock reserved for future issuance (in shares)	11.8
Common stock available for future grants (in shares)	5.1

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 35
-Paragraph 1D
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480483/718-10-35-1D

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 35
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480483/718-10-35-3

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
-Paragraph 2
-Subparagraph (c)(1)(i)
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-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
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-Subparagraph (c)(1)(ii)
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iii)
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-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iv)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iv)(01)
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-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iv)(02)
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iv)(03)
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-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iv)(04)
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-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(2)(i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Section 50
-Paragraph 2
-Subparagraph (c)(2)(iii)(01)
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
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Reference 23: http://www.xbrl.org/2003/role/disclosureRef
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Reference 24: http://www.xbrl.org/2003/role/disclosureRef
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Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (f)(2)(ii)
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Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (f)(2)(v)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

+ Details

INCOME TAXES - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets:
Net operating loss and other carryforwards	$ 236	$ 406
Derivative instruments	22	0
Stock based compensation	7	5
Viper's investment in Viper LLC	170	148
Rattler's investment in Rattler LLC	0	1
Other	21	16
Deferred tax assets	456	576
Valuation allowance	(233)	(223)
Deferred tax assets, net of valuation allowance	223	353
Deferred tax liabilities:
Oil and natural gas properties and equipment	2,463	2,109
Midstream investments	162	235
Derivative instruments	0	12
Other	2	2
Total deferred tax liabilities	2,627	2,358
Net deferred tax liabilities	$ 2,404	$ 2,005

DEBT - Long-term Debt (Details)	Dec. 31, 2023 USD ($) instrument	Oct. 19, 2023	Jun. 30, 2023	Dec. 31, 2022 USD ($)	Dec. 13, 2022	Oct. 28, 2022	Jun. 30, 2022	Mar. 17, 2022	Jun. 30, 2021 USD ($) instrument
Debt Instrument [Line Items]
Long-term debt, gross	$ 6,641,000,000			$ 6,248,000,000
Unamortized debt issuance costs	(46,000,000)			(43,000,000)
Unamortized discount costs	(23,000,000)			(26,000,000)
Unamortized premium costs	4,000,000			4,000,000
Current maturities of long-term debt	0			10,000,000
Total long-term debt	6,641,000,000			6,238,000,000
Number of instruments held \| instrument									2
Fair value of interest rate swap agreements
Debt Instrument [Line Items]
Fair value of interest rate swap agreements	$ (84,000,000)			(106,000,000)
Number of instruments held \| instrument	2
5.250% Senior Notes due 2023 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	5.25%
Long-term debt, gross	$ 0			10,000,000
3.250% Senior Notes due 2026 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	3.25%		3.25%
Long-term debt, gross	$ 750,000,000			780,000,000
5.625% Senior Notes due 2026 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	5.625%
Long-term debt, gross	$ 14,000,000			14,000,000
7.125% Medium-term Notes, Series B, due 2028 \| Medium-term Notes
Debt Instrument [Line Items]
Stated interest rate	7.125%						7.125%
Long-term debt, gross	$ 73,000,000			73,000,000
3.500% Senior Notes due 2029 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	3.50%		3.50%
Long-term debt, gross	$ 921,000,000			1,021,000,000
3.125% Senior Notes due 2031 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	3.125%						3.125%
Long-term debt, gross	$ 789,000,000			789,000,000
6.250% Senior Notes due 2033 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6.25%					6.25%
Long-term debt, gross	$ 1,100,000,000			1,100,000,000
4.400% Senior Notes due 2051 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	4.40%
Long-term debt, gross	$ 650,000,000			650,000,000
4.250% Senior Notes due 2052 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	4.25%							4.25%
Long-term debt, gross	$ 750,000,000			750,000,000
6.250% Senior Notes due 2053 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6.25%				6.25%
Long-term debt, gross	$ 650,000,000			650,000,000
Revolving credit facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	0
Viper revolving credit facility \| Viper \| Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	$ 263,000,000			152,000,000
Viper 5.375% Senior Notes due 2027 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	5.375%						5.375%
Viper 5.375% Senior Notes due 2027 \| Senior Notes \| Viper
Debt Instrument [Line Items]
Long-term debt, gross	$ 430,000,000			430,000,000
Viper 7.375% Senior Notes due 2031
Debt Instrument [Line Items]
Stated interest rate		7.375%
Viper 7.375% Senior Notes due 2031 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	7.375%
Viper 7.375% Senior Notes due 2031 \| Senior Notes \| Viper
Debt Instrument [Line Items]
Long-term debt, gross	$ 400,000,000			$ 0
Senior Notes Due 2029 \| Fair value of interest rate swap agreements \| Designated as Hedging Instrument
Debt Instrument [Line Items]
Fair value hedges									$ 1,200,000,000
Derivative, fixed interest rate									3.50%

SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

SEGMENT INFORMATION

The Company reports its operations in one reportable segment: 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. Other operations are included in the “All Other” category in the table below. The sources of the revenue included in the “All Other” category include midstream gathering, compression, water handling, disposal and treatment operations which are primarily derived from intersegment transactions for services provided to the upstream segment. The segments comprise the structure used by the Company’s 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		All Other		Eliminations		Total
	(In millions)
Year Ended December 31, 2023:
Third-party revenues	$	8,344	$	68	$	—	$	8,412
Intersegment revenues	—		329		(329)		—
Total revenues	$	8,344	$	397	$	(329)	$	8,412
Depreciation, depletion, amortization and accretion	$	1,707	$	39	$	—	$	1,746

Income (loss) from operations	$	4,519	$	129	$	(78)	$	4,570
Interest expense, net	$	(176)	$	1	$	—	$	(175)
Other income (expense)	$	(268)	$	88	$	(15)	$	(195)
Income (loss) from equity investments	$	(1)	$	49	$	—	$	48
Provision for (benefit from) income taxes	$	888	$	24	$	—	$	912
Net income (loss) attributable to non-controlling interest	$	193	$	—	$	—	$	193
Net income (loss) attributable to Diamondback Energy, Inc.	$	2,993	$	243	$	(93)	$	3,143
Total assets	$	28,362	$	1,242	$	(603)	$	29,001


	Upstream		All Other		Eliminations		Total
	(In millions)
Year Ended December 31, 2022:
Third-party revenues	$	9,572	$	71	$	—	$	9,643
Intersegment revenues	—		369		(369)		—
Total revenues	$	9,572	$	440	$	(369)	$	9,643
Depreciation, depletion, amortization and accretion	$	1,279	$	65	$	—	$	1,344

Income (loss) from operations	$	6,432	$	166	$	(90)	$	6,508
Interest expense, net	$	(130)	$	(29)	$	—	$	(159)
Other income (expense)	$	(653)	$	(21)	$	(16)	$	(690)
Income (loss) from equity investments	$	—	$	77	$	—	$	77
Provision for (benefit from) income taxes	$	1,165	$	9	$	—	$	1,174
Net income (loss) attributable to non-controlling interest	$	150	$	26	$	—	$	176
Net income (loss) attributable to Diamondback Energy, Inc.	$	4,334	$	158	$	(106)	$	4,386
Total assets	$	24,452	$	2,213	$	(456)	$	26,209


	Upstream		All Other		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)	$	23	$	(8)	$	(910)
Income (loss) from equity investments	$	—	$	15	$	—	$	15
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

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-15

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
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+ Details

ACQUISITIONS AND DIVESTITURES - Pro Forma Financial Information (Details) - QEP - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Revenues	$ 8,457	$ 10,542	$ 7,198
Income (loss) from operations	4,607	7,071	4,193
Net income (loss)	$ 3,175	$ 4,834	$ 2,148
Basic earnings per common share, (in dollars per share)	$ 17.48	$ 25.74	$ 11.40
Diluted earnings per common share, (in dollars per share)	$ 17.48	$ 25.74	$ 11.40

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS - Related Party (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Current assets - Accounts receivable	$ 654	$ 618
Current liabilities - Accrued capital expenditures	(493)	(480)
Current liabilities - Other accrued liabilities	(475)	(399)
Lease operating expenses	872	652	$ 565
Net income (loss)	3,336	$ 4,562	$ 2,276
Related Party
Related Party Transaction [Line Items]
Current assets - Accounts receivable	61
Current liabilities - Accrued capital expenditures	(21)
Current liabilities - Other accrued liabilities	(18)
Lease operating expenses	33
Net income (loss)	$ (33)

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

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+ Details

INCOME TAXES - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense at the federal statutory rate	$ 892	$ 1,205	$ 610
State income tax expense, net of federal tax effect	31	42	23
Non-deductible compensation	8	10	10
Change in valuation allowance	(7)	(71)	(12)
Other, net	(12)	(12)	0
Provision for (benefit from) income taxes	$ 912	$ 1,174	$ 631

- Definition

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

+ References + Details

ACQUISITIONS AND DIVESTITURES - Acquisitions (Details) shares in Thousands												12 Months Ended
	Nov. 01, 2023 USD ($) a shares	Oct. 31, 2023 USD ($)	Sep. 01, 2023 USD ($) county	Jan. 31, 2023 USD ($) a shares	Nov. 30, 2022 USD ($) a well shares	Jan. 18, 2022 USD ($) a	Oct. 21, 2021 USD ($) a	Oct. 05, 2021 USD ($) MMcf / d plant	Oct. 01, 2021 USD ($) a shares	Mar. 31, 2021 USD ($)	Feb. 26, 2021 USD ($) a well shares	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($) a well	Dec. 31, 2021 USD ($)	Dec. 13, 2022	Mar. 17, 2021 USD ($) a
Business Acquisition [Line Items]
Consideration received on transaction	$ 200,000,000	$ 200,000,000
Equity method investments												$ 529,000,000	$ 566,000,000
Number of counties \| county			12
Funds held in escrow												0	119,000,000
Proved properties												1,314,000,000	778,000,000	$ 2,805,000,000
Unproved properties												1,701,000,000	1,536,000,000	1,829,000,000
Long-term debt, gross												$ 6,641,000,000	6,248,000,000
6.250% Senior Notes due 2053 \| Senior Notes
Business Acquisition [Line Items]
Stated interest rate												6.25%			6.25%
Long-term debt, gross												$ 650,000,000	650,000,000
QEP
Business Acquisition [Line Items]
Proved properties										$ 2,000,000,000
Unproved properties										$ 733,000,000
Revenues since acquisition date														1,100,000,000
Net income since acquisition date														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, incurred by QEP														31,000,000
Rattler’s WTG Joint Venture Acquisition
Business Acquisition [Line Items]
Cash payment to acquire business								$ 104,000,000
Joint venture, interest acquired								25.00%
Rattler’s WTG Joint Venture Acquisition \| Midland Basin
Business Acquisition [Line Items]
Gas processing capacity \| MMcf / d								925
Rattler’s WTG Joint Venture Acquisition \| Midland Basin \| WTG Midstream LLC
Business Acquisition [Line Items]
Gas processing plants \| plant								6
QEP Merger and the Guidon Acquisition
Business Acquisition [Line Items]
Acquisition related costs														78,000,000
Williston Basin
Business Acquisition [Line Items]
Area of land \| a							95,000
Disposed of by Sale \| Water Assets
Business Acquisition [Line Items]
Loss on sale of assets												12,000,000
Disposed of by Sale \| Williston Basin
Business Acquisition [Line Items]
Loss on sale of assets							$ 0
Area of land \| a							95,000
Diamondback Energy, Inc.
Business Acquisition [Line Items]
Proceeds from equity method investment			$ 692,000,000
Deep Blue
Business Acquisition [Line Items]
Proceeds from sale of productive assets			516,000,000
Equity method investments			$ 126,000,000									$ 128,000,000	0
Ownership Interest			30.00%									30.00%
Contingent consideration receivable												$ 43,000,000
Agreement term			15 years
Deep Blue \| Five Point Energy LLC
Business Acquisition [Line Items]
Contingent consideration			$ 47,000,000
Deep Blue \| Five Point Energy LLC
Business Acquisition [Line Items]
Equity method investments			$ 251,000,000
Ownership Interest			70.00%
Viper Acquisition
Business Acquisition [Line Items]
Equity transferred (in shares) \| shares	9,020
Total consideration	$ 760,000,000
2023 Permian Basin Acquisition
Business Acquisition [Line Items]
Net royalty acres \| a	4,600
2023 Other Major Basin Acquisitions
Business Acquisition [Line Items]
Net royalty acres \| a	2,700
Deep Blue
Business Acquisition [Line Items]
Other commitment												500,000,000
Lario Acquisition
Business Acquisition [Line Items]
Total consideration				$ 1,447,000,000
Area of land \| a				25,000
Area of land, net \| a				16,000
Number of shares issued \| shares				4,330
Cash consideration				$ 814,000,000
Funds held in escrow				113,000,000
Proved properties				924,000,000
Unproved properties				$ 536,000,000
Revenues since acquisition date												488,000,000
Net income since acquisition date												200,000,000
Acquisition related costs												8,000,000
Firebird Acquisition
Business Acquisition [Line Items]
Total consideration					$ 1,663,000,000
Number of shares issued \| shares					5,921,000
Cash consideration					$ 787,000,000
Acquisition related costs												3,000,000	2,000,000
Firebird Acquisition \| Midland Basin
Business Acquisition [Line Items]
Area of land \| a					75,000
Area of land, net \| a					68,000
Number of shares issued \| shares					5,920
Funds held in escrow					$ 125,000,000
Proved properties					648,000,000
Unproved properties												$ 950,000,000
Revenues since acquisition date													46,000,000
Net income since acquisition date													28,000,000
Consideration transferred					$ 787,000,000
Number of additional wells \| well					854
2022 Acquisition Delaware Basin
Business Acquisition [Line Items]
Area of land \| a						6,200
Payments for asset acquisitions						$ 232,000,000
2022 Acquisition Permian Basin
Business Acquisition [Line Items]
Total consideration													$ 220,000,000
Net royalty acres \| a													4,000
Number of additional wells \| well													200
Guidon Operating LLC
Business Acquisition [Line Items]
Total consideration											$ 1,115,000,000
Number of shares issued \| shares											10,676
Cash consideration											$ 375,000,000
Proved properties														537,000,000
Unproved properties														573,000,000
Revenues since acquisition date														345,000,000
Net income since acquisition date														$ 170,000,000
Number of additional wells \| well											210
Guidon Operating LLC \| Northern Midland Basin
Business Acquisition [Line Items]
Area of land \| a											32,500
Viper’s Swallowtail Acquisition
Business Acquisition [Line Items]
Number of shares issued \| shares									15,250
Cash consideration									$ 225,000,000
Viper’s Swallowtail Acquisition \| Diamondback Energy, Inc
Business Acquisition [Line Items]
Percentage of shares acquired									62.00%
Viper’s Swallowtail Acquisition \| Northern Midland Basin
Business Acquisition [Line Items]
Area of land \| a									2,313
Viper’s Swallowtail Acquisition \| Viper’s Revolving Credit Facility
Business Acquisition [Line Items]
Long-term debt, gross									$ 190,000,000

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
Audit Information [Abstract]
Auditor Firm ID	248
Auditor Name	GRANT THORNTON LLP
Auditor Location	Oklahoma City, Oklahoma

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows - Proved Crude Oil and Natural Gas Reserves (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows	$ 106,418	$ 137,051	$ 77,085
Future development costs	(6,400)	(6,176)	(4,243)
Future production costs	(25,656)	(25,295)	(19,123)
Future production taxes	(7,434)	(9,927)	(5,572)
Future income tax expenses	(11,067)	(17,563)	(7,237)
Future net cash flows	55,861	78,090	40,910
10% discount to reflect timing of cash flows	(28,803)	(42,391)	(22,193)
Standardized measure of discounted future net cash flows	27,058	35,699	18,717	$ 6,758
Undiscounted future asset retirement costs	685	756	339
Oil and Gas, Delivery Commitment [Line Items]
Standardized measure of discounted future net cash flows	$ 27,058	$ 35,699	$ 18,717	$ 6,758
Viper
Oil and Gas, Delivery Commitment [Line Items]
Ownership percentage by noncontrolling parties	44.00%	44.00%	46.00%
Viper
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Standardized measure of discounted future net cash flows	$ 3,200	$ 3,500	$ 2,100
Oil and Gas, Delivery Commitment [Line Items]
Standardized measure of discounted future net cash flows	$ 3,200	$ 3,500	$ 2,100

PROPERTY AND EQUIPMENT - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
PROPERTY AND EQUIPMENT - Narrative (Details) - USD ($)	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Capitalized internal costs		$ 66,000,000	$ 58,000,000	$ 60,000,000
Timing of inclusion of costs in amortization calculation		10 years
Impairment of oil and natural gas properties		$ 0	0	$ 0
Exploration costs or development costs not subject to depletion		77,000,000	126,000,000
Capitalized interest not subject to depletion		$ 337,000,000	$ 206,000,000
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

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

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

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented under the captions “Derivative instruments” in the Company’s consolidated balance sheets as of December 31, 2023 and December 31, 2022.


	As of December 31, 2023
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	88	$	—	$	88	$	(71)	$	17

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	8	$	—	$	8	$	(7)	$	1

Non-current assets- Other assets:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	111	$	—	$	111	$	(71)	$	40
Interest rate swaps	$	—	$	46	$	—	$	46	$	—	$	46
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	12	$	—	$	12	$	(7)	$	5
Interest rate swaps	$	—	$	117	$	—	$	117	$	—	$	117


	As of December 31, 2022
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	197	$	—	$	197	$	(65)	$	132

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	62	$	—	$	62	$	(39)	$	23

Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	67	$	—	$	67	$	(65)	$	2
Interest rate swaps	$	—	$	45	$	—	$	45	$	—	$	45
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	39	$	—	$	39	$	(39)	$	—
Interest rate swaps	$	—	$	148	$	—	$	148	$	—	$	148

Schedule of Offsetting Assets


	As of December 31, 2023
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	88	$	—	$	88	$	(71)	$	17

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	8	$	—	$	8	$	(7)	$	1

Non-current assets- Other assets:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	111	$	—	$	111	$	(71)	$	40
Interest rate swaps	$	—	$	46	$	—	$	46	$	—	$	46
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	12	$	—	$	12	$	(7)	$	5
Interest rate swaps	$	—	$	117	$	—	$	117	$	—	$	117


	As of December 31, 2022
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	197	$	—	$	197	$	(65)	$	132

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	62	$	—	$	62	$	(39)	$	23

Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	67	$	—	$	67	$	(65)	$	2
Interest rate swaps	$	—	$	45	$	—	$	45	$	—	$	45
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	39	$	—	$	39	$	(39)	$	—
Interest rate swaps	$	—	$	148	$	—	$	148	$	—	$	148

Schedule of Offsetting Liabilities


	As of December 31, 2023
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	88	$	—	$	88	$	(71)	$	17

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	8	$	—	$	8	$	(7)	$	1

Non-current assets- Other assets:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	111	$	—	$	111	$	(71)	$	40
Interest rate swaps	$	—	$	46	$	—	$	46	$	—	$	46
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	12	$	—	$	12	$	(7)	$	5
Interest rate swaps	$	—	$	117	$	—	$	117	$	—	$	117


	As of December 31, 2022
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	197	$	—	$	197	$	(65)	$	132

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	62	$	—	$	62	$	(39)	$	23

Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	67	$	—	$	67	$	(65)	$	2
Interest rate swaps	$	—	$	45	$	—	$	45	$	—	$	45
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	39	$	—	$	39	$	(39)	$	—
Interest rate swaps	$	—	$	148	$	—	$	148	$	—	$	148

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, 2023				December 31, 2022
	Carrying				Carrying
	Value		Fair Value		Value		Fair Value
	(In millions)
Debt	$	6,641	$	6,507	$	6,248	$	5,754

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Dividends to Non-Controlling Interest (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Dividends [Line Items]
Dividends	$ 607	$ 151	$ 151	$ 546	$ 400	$ 532	$ 548	$ 108	$ 92	$ 83	$ 74	$ 69	$ 1,455	$ 1,588	$ 318
Viper
Dividends [Line Items]
Dividends													$ 129	182	76
Rattler LLC and Rattler Midstream GP LLC
Dividends [Line Items]
Dividends														$ 35	$ 36

ACQUISITIONS AND DIVESTITURES - Schedule of Asset Acquisition Consideration Paid (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Jan. 31, 2023	Nov. 30, 2022	Feb. 26, 2021
Lario Acquisition
Asset Acquisition [Line Items]
Shares of Diamondback common stock issued at closing	4,330
Closing price per share of Diamondback common stock on the closing date	$ 146.12
Fair value of Diamondback common stock issued	$ 633
Cash consideration	814
Total consideration (including fair value of Diamondback common stock issued)	$ 1,447
Firebird Acquisition
Asset Acquisition [Line Items]
Shares of Diamondback common stock issued at closing		5,921,000
Closing price per share of Diamondback common stock on the closing date		$ 148.02
Fair value of Diamondback common stock issued		$ 876
Cash consideration		787
Total consideration (including fair value of Diamondback common stock issued)		$ 1,663
Guidon Operating LLC
Asset Acquisition [Line Items]
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

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Change in Ownership of Consolidated Subsidiaries

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the respective periods:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Net income (loss) attributable to the Company	$	3,143	$	4,386	$	2,182
Change in ownership of consolidated subsidiaries	77		(46)		66
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest	$	3,220	$	4,340	$	2,248

Dividends

The following table presents dividends and distribution equivalent rights paid on the Company’s common stock during the respective periods:


	Base		Variable		Total		Total
	(In per share)						(In millions)
2023
First quarter	$	0.80	$	2.15	$	2.95	$	546
Second quarter	0.80		0.03		0.83		151
Third quarter	0.84		—		0.84		151
Fourth quarter	0.84		2.53		3.37		607
Total year-to-date	$	3.28	$	4.71	$	7.99	$	1,455

2022
First quarter	$	0.60	$	—	$	0.60	$	108
Second quarter	0.70		2.35		3.05		548
Third quarter	0.75		2.30		3.05		532
Fourth quarter	0.75		1.51		2.26		400
Total year-to-date	$	2.80	$	6.16	$	8.96	$	1,588

2021
First quarter	$	0.40	$	—	$	0.40	$	69
Second quarter	0.40		—		0.40		74
Third quarter	0.45		—		0.45		83
Fourth quarter	0.50		—		0.50		92
Total year-to-date	$	1.75	$	—	$	1.75	$	318

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,
	2023		2022		2021
	(In millions, except per share amounts)
Net income (loss) attributable to common stock	$	3,143	$	4,386	$	2,182
Less: distributed and undistributed earnings allocated to participating securities(1)	22		42		20
Net income (loss) attributable to common stockholders	$	3,121	$	4,344	$	2,162
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	179,999		176,539		176,643
Effect of dilutive securities:
Weighted-average potential common shares issuable	—		—		—
Diluted weighted average common shares outstanding	179,999		176,539		176,643
Basic net income (loss) attributable to common stock	$	17.34	$	24.61	$	12.24
Diluted net income (loss) attributable to common stock	$	17.34	$	24.61	$	12.24

(1) Unvested restricted stock awards and performance stock awards that contain non-forfeitable distribution equivalent rights are considered participating securities and therefore are included in the earnings per share calculation pursuant to the two-class method.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Impairment of long-lived assets	$ 0	$ 0	$ 0
Remaining performance obligation, amount	0
Equity method investment impairment	$ 0	$ 0	$ 0

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net income (loss)	$ 3,336	$ 4,562	$ 2,276
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	378	720	606
Depreciation, depletion, amortization and accretion	1,746	1,344	1,275
(Gain) loss on extinguishment of debt	4	99	75
(Gain) loss on derivative instruments, net	259	586	848
Cash received (paid) on settlement of derivative instruments	(110)	(850)	(1,247)
(Income) loss from equity investment, net	(48)	(77)	(15)
Equity-based compensation expense	54	55	51
Other	5	85	39
Changes in operating assets and liabilities:
Accounts receivable	(71)	(47)	(196)
Income tax receivable	283	(283)	152
Prepaid expenses and other current assets	(89)	21	20
Accounts payable and accrued liabilities	57	(47)	(41)
Income taxes payable	(5)	17	0
Revenues and royalties payable	123	156	148
Other	(2)	(16)	(47)
Net cash provided by (used in) operating activities	5,920	6,325	3,944
Cash flows from investing activities:
Drilling, completions and infrastructure additions to oil and natural gas properties	(2,582)	(1,854)	(1,457)
Additions to midstream assets	(119)	(84)	(30)
Property acquisitions	(2,013)	(1,675)	(787)
Proceeds from sale of assets	1,407	327	820
Other	(16)	(44)	(85)
Net cash provided by (used in) investing activities	(3,323)	(3,330)	(1,539)
Cash flows from financing activities:
Proceeds from borrowings under credit facilities	4,779	5,204	1,313
Repayments under credit facilities	(4,668)	(5,551)	(1,000)
Proceeds from senior notes	400	2,500	2,200
Repayment of senior notes	(134)	(2,410)	(3,193)
Proceeds from (repayments to) joint venture	0	(74)	(20)
Premium on extinguishment of debt	0	(63)	(178)
Repurchased shares under buyback program	(840)	(1,098)	(431)
Repurchased shares/units under Viper's buyback program	(95)	(153)	(94)
Dividends paid to stockholders	(1,444)	(1,572)	(312)
Dividends/distributions to non-controlling interest	(129)	(217)	(112)
Financing portion of net cash received (paid) for derivative instruments	0	0	22
Other	(45)	(69)	(36)
Net cash provided by (used in) financing activities	(2,176)	(3,503)	(1,841)
Net increase (decrease) in cash and cash equivalents	421	(508)	564
Cash, cash equivalents and restricted cash at beginning of period	164	672	108
Cash, cash equivalents and restricted cash at end of period	$ 585	$ 164	$ 672

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / Boe	Dec. 31, 2022 USD ($) $ / Boe	Dec. 31, 2021 USD ($) $ / Boe
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization excluding amortization of financing costs	$ 1,746	$ 1,344	$ 1,275
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 (usd per BOE) \| $ / Boe	10.21	8.87	8.77
Depreciation, depletion and amortization excluding amortization of financing costs	$ 1,700	$ 1,300	$ 1,200

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net income (loss) attributable to Diamondback Energy, Inc.	$ 3,143	$ 4,386	$ 2,182

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147483443/250-10-50-3

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147483443/250-10-50-4

Reference 13: http://www.xbrl.org/2003/role/exampleRef
-Topic 946
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-Name Accounting Standards Codification
-Section 55
-Paragraph 10
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-URI https://asc.fasb.org//1943274/2147480167/946-830-55-10

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 7
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-URI https://asc.fasb.org//1943274/2147483581/946-220-45-7

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION	12 Months Ended
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION	DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION Organization and Description of the Business Diamondback Energy, Inc., together with its subsidiaries (collectively referred to as “Diamondback” or the “Company” unless the context otherwise requires), is an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. As of December 31, 2023, the wholly-owned subsidiaries of Diamondback include Diamondback E&P LLC (“Diamondback E&P”), a Delaware limited liability company, Rattler Midstream GP LLC, a Delaware limited liability company (“Rattler’s GP”), Rattler Midstream LP, a Delaware limited partnership (“Rattler”), 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. Rattler Merger On August 24, 2022 (the “Effective Date”), the Company completed the merger with Rattler pursuant to which the Company acquired all of the approximately 38.51 million publicly held outstanding common units of Rattler in exchange for approximately 4.35 million shares of the Company’s common stock (the “Rattler Merger”). Rattler continued as the surviving entity. Following the Rattler Merger, the Company owns all of Rattler’s outstanding common units and Class B units, and Rattler GP remains the general partner of Rattler. Following the closing of the Rattler Merger, Rattler’s common units were delisted from Nasdaq and Rattler filed a certification on Form 15 with the SEC requesting the deregistration of its common units and suspension of Rattler’s reporting obligations under the Exchange Act. The Rattler Merger was accounted for as a non-cash equity transaction resulting in increases to common stock of $44 thousand, additional paid-in-capital of $344 million, merger and integration expense of $11 million and a decrease in noncontrolling interests in consolidated subsidiaries of $344 million. For periods prior to the Effective Date, the results of operations attributable to the non-controlling interest in Rattler are presented within equity and net income and are shown separately from the equity and net income attributable to the Company. Viper Conversion to Corporate Structure On November 13, 2023, the Company’s publicly traded subsidiary, Viper Energy Partners, LP completed its conversion from a Delaware limited partnership into a Delaware corporation, Viper Energy, Inc. (“Viper”) (“the Viper Conversion”). At the time of the Viper Conversion, each of the Company’s common units representing limited partnership interest in Viper Energy Partners, LP was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class A common stock of Viper Energy, Inc., and each of the Company’s Class B unit representing limited partnership interest in Viper Energy Partners, LP was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class B common stock of Viper Energy, Inc. Viper is now a “controlled company” under the Nasdaq rules because the Company owns more than 50% of the voting power of Viper’s common stock. Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation. Viper is consolidated in the Company’s financial statements. On October 31, 2023, pursuant to a common unit purchase and sale agreement entered into on September 4, 2023, Viper issued approximately 7.22 million of its common units, which were converted to shares of Viper Class A common stock at the time of the Viper Conversion, to the Company at a price of $27.72 per unit for total consideration to Viper of approximately $200 million. As of December 31, 2023, the Company owned approximately 56% of Viper’s combined outstanding Class A common stock and Class B common stock. The results of operations attributable to the non-controlling interest in Viper are presented within equity and net income and are shown separately from the equity and net income attributable to the Company. The Company has 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 includes the activities of Viper, and (ii) the midstream operations segment, which owns and operates certain midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Prior to the Rattler Merger, both the upstream operations segment and the midstream operations segment were considered reportable segments. Following the Rattler Merger, the Company determined only the upstream operations segment met the quantitative requirements of a reportable segment. 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.

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization excluded	$ 8,659	$ 8,355
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	400,000,000	400,000,000
Common stock, shares issued (in shares)	178,723,871	179,840,797
Common stock, shares outstanding (in shares)	178,723,871	179,840,797

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Viper’s Common Stock Repurchase Program (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program authorized amount	$ 4,000,000,000
Stock repurchase program amount repurchased	840,000,000	$ 1,098,000,000	$ 431,000,000
Stock repurchase remaining authorized amount	1,600,000,000
Common Class A \| Viper
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program authorized amount	750,000,000
Stock repurchase program amount repurchased	95,000,000	$ 151,000,000	$ 46,000,000
Stock repurchase remaining authorized amount	$ 434,000,000

- Definition

Equity impact of the value of stock that has been repurchased during the period and has not been retired and is not held in treasury. Some state laws may mandate the circumstances under which an entity may acquire its own stock and prescribe the accounting treatment therefore. This element is used when state law does not recognize treasury stock.

+ References + Details

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil, natural gas and natural gas liquid sales	$ 8,228	$ 9,566	$ 6,747
Production costs	(1,684)	(1,521)	(1,202)
Depreciation, depletion, amortization and accretion	(1,684)	(1,264)	(1,211)
Income tax benefit (expense)	(1,000)	(1,437)	(918)
Results of operations	$ 3,860	$ 5,344	$ 3,416

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2023
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. Viper is consolidated in the Company’s financial statements. On October 31, 2023, pursuant to a common unit purchase and sale agreement entered into on September 4, 2023, Viper issued approximately 7.22 million of its common units, which were converted to shares of Viper Class A common stock at the time of the Viper Conversion, to the Company at a price of $27.72 per unit for total consideration to Viper of approximately $200 million. As of December 31, 2023, the Company owned approximately 56% of Viper’s combined outstanding Class A common stock and Class B common stock. The results of operations attributable to the non-controlling interest in Viper are presented within equity and net income and are shown separately from the equity and net income attributable to the Company. The Company has 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 includes the activities of Viper, and (ii) the midstream operations segment, which owns and operates certain midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Prior to the Rattler Merger, both the upstream operations segment and the midstream operations segment were considered reportable segments. Following the Rattler Merger, the Company determined only the upstream operations segment met the quantitative requirements of a reportable segment.
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. For instance, war in Ukraine and Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of these events and changing market conditions. 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, fair value estimates of derivative instruments, the fair value determination of acquired assets and liabilities assumed, and estimates of income taxes, including deferred tax valuation allowances.
Cash, Cash Equivalents and Restricted Cash	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 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. 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 utilizing the loss-rate method, which considers 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 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. From the second quarter of 2021 through the second quarter of 2022, the Company had certain interest rate swaps 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 during those periods completely offset changes in the fair value of the hedged portion of the underlying debt. In the second quarter of 2022, the Company elected to fully dedesignate these interest rate swaps and hedge accounting was discontinued.
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 internal 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. 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 $10.21, $8.87 and $8.77 for the years ended December 31, 2023, 2022 and 2021, respectively. Depletion expense for oil and natural gas properties was $1.7 billion, $1.3 billion and $1.2 billion for the years ended December 31, 2023, 2022 and 2021, respectively. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized oil and natural gas properties 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 on proved oil and natural gas properties, see Note 5—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.
Other Property, Equipment and Land	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 the estimated useful lives of the assets
Equity Method Investments	Equity Method Investments The Company accounts for its corporate joint ventures and equity investments 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 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 of accounting, the Company’s share of the investee’s earnings or loss is recognized in the statement of operations. As of December 31, 2023, the Company’s proportionate share of the income or loss from equity method investments is recognized on a one or two-month lag for its 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 non-controlling 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 a loss has occurred, the Company recognizes an impairment provision. There were no significant impairments of the Company’s equity investments for the years ended December 31, 2023, 2022 and 2021.
Investments in Real Estate	Investments in Real Estate The Company has invested in certain real estate assets which 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.
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 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.
Inventories	Inventories Inventories are stated at the lower of cost or net realizable value and primarily consist of tubular goods and equipment at December 31, 2023 and 2022. 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 8—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 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 Interest	Non-controlling Interests Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper as well as Rattler prior to the Rattler Merger, and are presented as a component of equity. When the Company’s relative ownership interests change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, occur. Because these changes in the ownership interests 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 prior to the Rattler Merger 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 deductions. 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. Net sales of purchased oil The Company enters into pipeline capacity commitments in order to secure available transportation capacity from the Company's areas of production for its commodities. Beginning in the third quarter of 2023, the Company has also entered into purchase transactions with third parties and separate sale transactions with third parties to satisfy certain of its unused oil pipeline capacity commitments. Revenues and expenses from these transactions are generally presented on a gross basis in the captions “Sales of purchased oil” and “Purchased oil expense” in the accompanying consolidated statements of operations as the Company acts as a principal in the transaction by assuming both the risks and rewards of ownership, including credit risk, of the oil volumes purchased and the responsibility to deliver the oil volumes sold. 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 the Company’s 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, 2023, 2022 and 2021 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.
Accounting for Equity-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, prior to the Rattler Merger, have granted various unit-based awards including unit options and phantom units to employees, officers and directors who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 10—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 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 required the acquirer in a business combination to record contract assets and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. The Company adopted this update effective January 1, 2023. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In March 2023, the FASB issued ASU 2023-01, “Leases (Topic 842) – Common Control Arrangements.” This update (i) requires all lessees that are a party to a lease between entities under common control in which there are leasehold improvements to record amortization utilizing the shorter period of the remaining lease term and the useful life of the improvements, and (ii) requires leasehold improvements to be accounted for as a transfer between entities under common control through an adjustment to equity if, and when, the lessee no longer controls the use of the underlying asset. This update is effective for fiscal years beginning after December 15, 2023 with early adoption permitted. The Company may adopt this update (i) prospectively to all new leasehold improvements on or after the date of adoption, (ii) prospectively to all new and existing leasehold improvements on or after the date of adoption, or (iii) retrospectively to the beginning of the period in which the Company first applied Topic 842. 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. In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures,” which updates reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. Management is currently evaluating this ASU to determine its impact on the Company's disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity. In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated, and provides additional requirements regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity. The Company considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.
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. See Note 4—Acquisitions and Divestitures for discussion of the fair values of proved oil and natural gas properties assumed in business combinations.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2023

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. For instance, war in Ukraine and Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of these events and changing market conditions. 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, fair value estimates of derivative instruments, the fair value determination of acquired assets and liabilities assumed, and estimates of income taxes, including deferred tax valuation allowances.

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.

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 utilizing the loss-rate method, which considers 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, 2023 and 2022, 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. From the second quarter of 2021 through the second quarter of 2022, the Company had certain interest rate swaps 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 during those periods completely offset changes in the fair value of the hedged portion of the underlying debt. In the second quarter of 2022, the Company elected to fully dedesignate these interest rate swaps and hedge accounting was discontinued. For additional information regarding the Company’s derivative instruments, see Note 12—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 internal 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. 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 $10.21, $8.87 and $8.77 for the years ended December 31, 2023, 2022 and 2021, respectively. Depletion expense for oil and natural gas properties was $1.7 billion, $1.3 billion and $1.2 billion for the years ended December 31, 2023, 2022 and 2021, respectively.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized oil and natural gas properties 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 on proved oil and natural gas properties, see Note 5—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.

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 the estimated useful lives of the assets, which range from three years to 30 years.

Equity Method Investments

The Company accounts for its corporate joint ventures and equity investments 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 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 of accounting, the Company’s share of the investee’s earnings or loss is recognized in the statement of operations. As of December 31, 2023, the Company’s proportionate share of the income or loss from equity method investments is recognized on a one or two-month lag for its 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 non-controlling 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 a loss has occurred, the Company recognizes an impairment provision. There were no significant impairments of the Company’s equity investments for the years ended December 31, 2023, 2022 and 2021. See Note 7—Equity Method Investments and Related Party Transactions for further details.

Investments in Real Estate

The Company has invested in certain real estate assets which 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.

Investments in real estate, excluding insignificant unamortized in-place lease and above-market lease intangibles, consist of the following:


	Estimated Useful Lives	December 31,
		2023		2022
	(Years)	(In millions)
Buildings	20-30	$	98	$	96
Tenant improvements	5 - 13	5		5
Land	N/A	1		1
Land improvements	5 - 15	1		1
Total real estate assets		105		103
Less: accumulated depreciation and amortization		(23)		(20)
Total investment in land and buildings, net		$	82	$	83

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 6—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, 2023, 2022 and 2021.

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 8—Debt for further details.

Inventories

Inventories are stated at the lower of cost or net realizable value and primarily consist of tubular goods and equipment at December 31, 2023 and 2022. 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 8—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

The Company’s accrued liabilities are financial instruments for which the carrying value approximates fair value.

Other accrued liabilities consist of the following at December 31, 2023, and 2022:


	December 31,
	2023		2022
	(In millions)
Derivative liability payable	$	13	$	21
Lease operating expenses payable	160		131
Ad valorem taxes payable	129		108
Accrued compensation	38		35
Interest payable	73		49
Midstream operating expenses payable	8		15
Other	54		40
Total other accrued liabilities	$	475	$	399

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 as well as Rattler prior to the Rattler Merger, and are presented as a component of equity. When the Company’s relative ownership interests change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, occur. Because these changes in the ownership interests 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 prior to the Rattler Merger and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 9—Stockholders' Equity and Earnings Per Share for a discussion of changes in the Company’s ownership interest in consolidated subsidiaries during the years ended December 31, 2023, 2022 and 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 deductions. 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.

Net sales of purchased oil

The Company enters into pipeline capacity commitments in order to secure available transportation capacity from the Company's areas of production for its commodities. Beginning in the third quarter of 2023, the Company has also entered into purchase transactions with third parties and separate sale transactions with third parties to satisfy certain of its unused oil pipeline capacity commitments. Revenues and expenses from these transactions are generally presented on a gross basis in the captions “Sales of purchased oil” and “Purchased oil expense” in the accompanying consolidated statements of operations as the Company acts as a principal in the transaction by assuming both the risks and rewards of ownership, including credit risk, of the oil volumes purchased and the responsibility to deliver the oil volumes sold.

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 the Company’s 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, 2023, 2022 and 2021 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.

See Note 3—Revenue from Contracts with Customers for additional discussion of the Company’s revenues.

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, prior to the Rattler Merger, have granted various unit-based awards including unit options and phantom units to employees, officers and directors who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 10—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 11—Income Taxes.

Accumulated Other Comprehensive Income (Loss)

The following table provides changes in the components of accumulated other comprehensive income, net of related income tax effects related to insignificant pension and postretirement benefit plans the Company acquired from Energen and QEP (in millions):


	Year Ended December 31,
	2023		2022
	(In millions)
Balance at beginning of the period	$	(7)	$	—
Net actuarial gain (loss) on pension and postretirement benefit plans	(1)		(9)
Income tax benefit (expense)	—		2
Balance at end of the period	$	(8)	$	(7)

Recent Accounting Pronouncements

Recently Adopted Pronouncements

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 required the acquirer in a business combination to record contract assets and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it

had originated the contract, rather than at fair value. The Company adopted this update effective January 1, 2023. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In March 2023, the FASB issued ASU 2023-01, “Leases (Topic 842) – Common Control Arrangements.” This update (i) requires all lessees that are a party to a lease between entities under common control in which there are leasehold improvements to record amortization utilizing the shorter period of the remaining lease term and the useful life of the improvements, and (ii) requires leasehold improvements to be accounted for as a transfer between entities under common control through an adjustment to equity if, and when, the lessee no longer controls the use of the underlying asset. This update is effective for fiscal years beginning after December 15, 2023 with early adoption permitted. The Company may adopt this update (i) prospectively to all new leasehold improvements on or after the date of adoption, (ii) prospectively to all new and existing leasehold improvements on or after the date of adoption, or (iii) retrospectively to the beginning of the period in which the Company first applied Topic 842. 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.

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures,” which updates reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. Management is currently evaluating this ASU to determine its impact on the Company's disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated, and provides additional requirements regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.

The Company considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 347	$ 171
Additional liabilities incurred	4	36
Liabilities acquired	8	19	$ 65
Liabilities settled and divested	(88)	(26)
Accretion expense	16	14
Revisions in estimated liabilities(1)	(42)	133
Asset retirement obligations, end of period	245	347	$ 171
Less: current portion	6	11
Asset retirement obligations - long-term	$ 239	$ 336

DEBT

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

DEBT

The Company’s debt consisted of the following as of the dates indicated:


	December 31,
	2023		2022
	(In millions)
5.250% Senior Notes due 2023	$	—	$	10
3.250% Senior Notes due 2026	750		780
5.625% Senior Notes due 2026(1)	14		14
7.125% Medium-term Notes, Series B, due 2028	73		73
3.500% Senior Notes due 2029	921		1,021
3.125% Senior Notes due 2031	789		789
6.250% Senior Notes due 2033	1,100		1,100
4.400% Senior Notes due 2051	650		650
4.250% Senior Notes due 2052	750		750
6.250% Senior Notes due 2053	650		650
Unamortized debt issuance costs	(46)		(43)
Unamortized discount costs	(23)		(26)
Unamortized premium costs	4		4
Unamortized basis adjustment of dedesignated interest rate swap agreements(2)	(84)		(106)

Viper revolving credit facility	263		152
Viper 5.375% Senior Notes due 2027	430		430
Viper 7.375% Senior Notes due 2031	400		—
Total debt, net	6,641		6,248
Less: current maturities of long-term debt	—		10
Total long-term debt	$	6,641	$	6,238

(1) 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.

(2) Represents the unamortized basis adjustment related to two receive-fixed, pay variable interest rate swap agreements which were previously designated as fair value hedges of the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. These swaps were dedesignated in the second quarter of 2022 as discussed further in Note 12—Derivatives.

Debt maturities as of December 31, 2023, excluding debt issuance costs, premiums and discounts and the unamortized basis adjustment of dedesignated interest rate swap agreements are as follows:


Year Ending December 31,
	(In millions)
2024	$	—
2025	—
2026	764
2027	430
2028	336
Thereafter	5,260
Total	$	6,790

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 maintains a credit agreement, as amended, which provides for a maximum credit amount of $1.6 billion, which may be further increased to a total maximum commitment of $2.6 billion. As of December 31, 2023, the Company had no outstanding borrowings under the credit agreement and $1.6 billion available for future borrowings. The weighted average interest rate on borrowings under the credit agreement was 6.31%, 3.91% and 1.67% for the years ended December 31, 2023, 2022 and 2021, respectively. During the second quarter of 2023, the Company exercised an election to extend the maturity date of the credit agreement by one year to June 2, 2028, which may be further extended by one one-year extension pursuant to the terms set forth in the credit agreement.

Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by Diamondback E&P that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month Adjusted Term SOFR plus 1.0%), in each case plus the applicable margin. After giving effect to the amendment, (i) the applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate, and from 1.125% to 2.000% per annum in the case of Adjusted Term SOFR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on the Company’s long-term senior unsecured debt ratings.

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%. As of December 31, 2023, the Company was in compliance with all financial maintenance covenants under the revolving credit facility, as then in effect.

2023 Issuance of Notes

Viper 2031 Notes

On October 19, 2023, Viper completed an offering of $400 million in aggregate principal amount of its 7.375% Senior Notes maturing on November 1, 2031 (the “Viper 2031 Notes”). Viper received net proceeds of approximately $394 million, after deducting the initial purchasers’ discount and transaction costs, from the Viper 2031 Notes. Viper loaned the gross proceeds to Viper LLC, which used the proceeds to partially fund the cash portion of the GRP Acquisition.

2023 Retirement of Notes

In the second quarter of 2023, the Company repurchased principal amounts of $30 million of its 3.250% Senior Notes due 2026 and $100 million of its 3.500% Senior Notes due 2029 for total cash consideration, including accrued interest paid, of $124 million. These repurchases resulted in an immaterial loss on extinguishment of debt during the year ended December 31, 2023.

The Company redeemed the principal amount of its $10 million 5.250% Senior Notes due 2023 at maturity on May 1, 2023.

2022 Issuance of Notes

2053 Notes Offering

On December 13, 2022, the Company issued $650 million aggregate principal amount of 6.250% Senior Notes due March 15, 2053 (the “2053 Notes”) and received net proceeds of $643 million, after deducting debt issuance costs and discounts of $7 million and underwriting discounts and offering expenses. Interest on the 2053 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on March 15, 2023.

2033 Notes Offering

On October 28, 2022, the Company issued $1.1 billion of 6.250% Senior Notes due March 15, 2033 (the “2033 Notes”) and received net proceeds of $1.1 billion, after deducting debt issuance costs and discounts of $15 million and underwriting discounts and offering expense. Interest on the 2033 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on March 15, 2023.

2052 Notes Offering

On March 17, 2022, the Company issued $750 million aggregate principal amount of 4.250% Senior Notes due March 15, 2052 (the “2052 Notes”) and received net proceeds of $739 million, after deducting debt issuance costs and discounts of $11 million and underwriting discounts and offering expenses. Interest on the 2052 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on September 15, 2022.

2022 Retirement of Notes

In the third quarter of 2022, the Company fully redeemed the $25 million principal amount of the outstanding 5.375% Notes due 2022 and fully repaid at maturity the $20 million principal amount of the outstanding 7.320% Medium-term Notes, Series A due 2022. The Company funded these transactions with cash on hand.

Additionally, the Company used a portion of the net proceeds from the 2033 Notes offering to fund, in full, the redemption of the $500 million principal amount of Rattler’s 5.625% Senior Notes due 2025. The redemption included a premium and accrued and unpaid interest for a total cash consideration of $522 million. These redemptions resulted in an immaterial loss on extinguishment of debt.

In the second quarter of 2022, the Company repurchased principal amounts of $27 million of its 7.125% Medium-term Notes due 2028, $111 million of its 3.125% Senior Notes due 2031, $179 million of its 3.500% Senior Notes due 2029 and $20 million of its 3.250% Senior Notes due 2026 for total cash consideration, including accrued interest of $322 million.

Additionally, during the second quarter of 2022, Viper repurchased $50 million in principal amount of its 5.375% Senior Notes due 2027 for total cash consideration of $49 million. These repurchases resulted in an immaterial loss on extinguishment of debt. The Company funded its repurchases with cash on hand and Viper funded its repurchases with cash on hand and borrowings under the Viper credit agreement.

In the first quarter of 2022, the Company fully redeemed the $500 million and $1.0 billion principal amounts of its outstanding 4.750% Senior Notes due 2025 and 2.875% Senior Notes due 2024, respectively. Cash consideration for these redemptions totaled $1.6 billion, including make-whole premiums of $47 million, which resulted in a loss on extinguishment of debt of $54 million. The Company funded the redemptions with a portion of the net proceeds from the 2052 Notes offering and cash on hand.

Guaranteed Senior Notes

The Guaranteed Senior Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P, 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 Viper Notes are senior unsecured obligations of Viper, initially guaranteed on a senior unsecured basis by Viper LLC, and will pay interest semi-annually. The Company will not guarantee the Viper Notes. In the future, each of Viper’s restricted subsidiaries that either (i) guarantees any of its or a guarantor’s indebtedness, or (ii) is a domestic restricted subsidiary and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Viper Notes.

Viper’s Credit Agreement

On May 31, 2023, Viper LLC entered into a tenth amendment to the existing credit agreement, which among other things, (i) maintained the maximum credit amount of $2.0 billion, (ii) increased the borrowing base from $580 million to $1.0 billion and (iii) increased the aggregate elected commitment amount from $500 million to $750 million.

On September 22, 2023, Viper LLC entered into an eleventh and separately a twelfth amendment to the existing credit agreement, which among other things, (i) extended the maturity date from June 2, 2025, to September 22, 2028, (ii) maintained the maximum credit amount of $2.0 billion, (iii) further increased the borrowing base from $1.0 billion to $1.3 billion, (iv) further increased the aggregate elected commitment amount from $750 million to $850 million, and (v) waived the automatic reduction of the borrowing base that otherwise would have occurred upon the consummation of the issuance of the 2031 Notes.

As of December 31, 2023, Viper LLC had $263 million of outstanding borrowings and $587 million available for future borrowings under the Viper credit agreement. The weighted average interest rates on borrowings under the Viper credit agreement were 7.41%, 4.22%, and 2.35% for the years ended December 31, 2023, 2022 and 2021, respectively.

The outstanding borrowings under the Viper credit agreement bear interest at a rate elected by Viper LLC that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”), or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 1-month Adjusted Term SOFR plus 1.0%), in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternative base rate and from 2.00% to 3.00% per annum in the case of Adjusted Term SOFR, in each case depending on the amount of the 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. The credit agreement is secured by substantially all the assets of Viper and Viper LLC.

The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, 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

As of December 31, 2023, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2023, 2022 and 2021:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Interest expense	$	346	$	272	$	277
Other fees and expenses	2		12		11
Less: interest income	2		1		1
Less: capitalized interest	171		124		88
Interest expense, net	$	175	$	159	$	199

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//470/tableOfContent

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1E
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1E

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
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-Paragraph 1I
-Subparagraph (b)
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-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

+ Details

DERIVATIVES - Open Derivative Positions (Details) bbl in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2023 MMBTU $ / bbl $ / MMBTU bbl
OIL \| 2024 \| Jan. - Jun. \| Costless Collar \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	6
Weighted Average Differential (usd per Bbl	0
Weighted Average Floor Price (per Bbl/MMBtu)	65.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	95.55
OIL \| 2024 \| Jan. - Dec. \| Basis Swap \| Argus WTI Midland
Derivative [Line Items]
Volume (Bbls) \| bbl	10
Weighted Average Differential (usd per Bbl	1.19
Weighted Average Floor Price (per Bbl/MMBtu)	0
Weighted Average Ceiling Price (per Bbl/MMBtu)	0
OIL \| 2024 \| Jan. - Dec. \| Roll Swap \| WTI
Derivative [Line Items]
Volume (Bbls) \| bbl	30
Weighted Average Differential (usd per Bbl	0.81
Weighted Average Floor Price (per Bbl/MMBtu)	0
Weighted Average Ceiling Price (per Bbl/MMBtu)	0
OIL \| 2024 \| Jul. - Dec. \| Costless Collar \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	4
Weighted Average Differential (usd per Bbl	0
Weighted Average Floor Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	93.66
OIL \| 2024 \| Jan. - Mar. \| Put Option [Member] \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	16
Strike Price (per Bbl/MMBtu)	58.13
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.54
OIL \| 2024 \| Jan. - Mar. \| Put Option [Member] \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	124
Strike Price (per Bbl/MMBtu)	55.40
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.48
OIL \| 2024 \| Jan. - Mar. \| Put Option [Member] \| Argus WTI Houston
Derivative [Line Items]
Volume (Bbls) \| bbl	32
Strike Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.60
OIL \| 2024 \| Apr. - Jun. \| Put Option [Member] \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	14
Strike Price (per Bbl/MMBtu)	59.29
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.51
OIL \| 2024 \| Apr. - Jun. \| Put Option [Member] \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	108
Strike Price (per Bbl/MMBtu)	55.46
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.49
OIL \| 2024 \| Apr. - Jun. \| Put Option [Member] \| Argus WTI Houston
Derivative [Line Items]
Volume (Bbls) \| bbl	26
Strike Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.56
OIL \| 2024 \| Jul. - Sep. \| Put Option [Member] \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	2
Strike Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.53
OIL \| 2024 \| Jul. - Sep. \| Put Option [Member] \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	66
Strike Price (per Bbl/MMBtu)	55.15
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.53
OIL \| 2024 \| Jul. - Sep. \| Put Option [Member] \| Argus WTI Houston
Derivative [Line Items]
Volume (Bbls) \| bbl	18
Strike Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.55
OIL \| 2024 \| Oct. - Dec. \| Put Option [Member] \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	2
Strike Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.53
OIL \| 2024 \| Oct. - Dec. \| Put Option [Member] \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	34
Strike Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.61
OIL \| 2024 \| Oct. - Dec. \| Put Option [Member] \| Argus WTI Houston
Derivative [Line Items]
Volume (Bbls) \| bbl	4
Strike Price (per Bbl/MMBtu)	55.00
Weighted Average Ceiling Price (per Bbl/MMBtu)	1.72
NATURAL GAS \| 2024 \| Jan. - Dec. \| Basis Swap \| Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	380
Weighted Average Differential (usd per Bbl \| $ / MMBTU	(1.18)
Weighted Average Floor Price (per Bbl/MMBtu) \| $ / MMBTU	0
Weighted Average Ceiling Price (per Bbl/MMBtu) \| $ / MMBTU	0
NATURAL GAS \| 2024 \| Jan. - Dec. \| Costless Collar \| Henry Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	290
Weighted Average Differential (usd per Bbl \| $ / MMBTU	0
Weighted Average Floor Price (per Bbl/MMBtu) \| $ / MMBTU	2.83
Weighted Average Ceiling Price (per Bbl/MMBtu) \| $ / MMBTU	7.52
NATURAL GAS \| 2025 \| Jan. - Dec. \| Basis Swap \| Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	310
Weighted Average Differential (usd per Bbl \| $ / MMBTU	(0.69)
Weighted Average Floor Price (per Bbl/MMBtu) \| $ / MMBTU	0
Weighted Average Ceiling Price (per Bbl/MMBtu) \| $ / MMBTU	0

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule of Real Estate Assets

Investments in real estate, excluding insignificant unamortized in-place lease and above-market lease intangibles, consist of the following:


	Estimated Useful Lives	December 31,
		2023		2022
	(Years)	(In millions)
Buildings	20-30	$	98	$	96
Tenant improvements	5 - 13	5		5
Land	N/A	1		1
Land improvements	5 - 15	1		1
Total real estate assets		105		103
Less: accumulated depreciation and amortization		(23)		(20)
Total investment in land and buildings, net		$	82	$	83

Schedule of Other Accrued Liabilities

Other accrued liabilities consist of the following at December 31, 2023, and 2022:


	December 31,
	2023		2022
	(In millions)
Derivative liability payable	$	13	$	21
Lease operating expenses payable	160		131
Ad valorem taxes payable	129		108
Accrued compensation	38		35
Interest payable	73		49
Midstream operating expenses payable	8		15
Other	54		40
Total other accrued liabilities	$	475	$	399

Schedule of Accumulated Other Comprehensive Income (Loss)


	Year Ended December 31,
	2023		2022
	(In millions)
Balance at beginning of the period	$	(7)	$	—
Net actuarial gain (loss) on pension and postretirement benefit plans	(1)		(9)
Income tax benefit (expense)	—		2
Balance at end of the period	$	(8)	$	(7)

DEBT - Financial Covenant Table (Details) - Viper revolving credit facility	Dec. 31, 2023
Maximum
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	2.5
Minimum
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0

DEBT (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Schedule of Long-term Debt

The Company’s debt consisted of the following as of the dates indicated:


	December 31,
	2023		2022
	(In millions)
5.250% Senior Notes due 2023	$	—	$	10
3.250% Senior Notes due 2026	750		780
5.625% Senior Notes due 2026(1)	14		14
7.125% Medium-term Notes, Series B, due 2028	73		73
3.500% Senior Notes due 2029	921		1,021
3.125% Senior Notes due 2031	789		789
6.250% Senior Notes due 2033	1,100		1,100
4.400% Senior Notes due 2051	650		650
4.250% Senior Notes due 2052	750		750
6.250% Senior Notes due 2053	650		650
Unamortized debt issuance costs	(46)		(43)
Unamortized discount costs	(23)		(26)
Unamortized premium costs	4		4
Unamortized basis adjustment of dedesignated interest rate swap agreements(2)	(84)		(106)

Viper revolving credit facility	263		152
Viper 5.375% Senior Notes due 2027	430		430
Viper 7.375% Senior Notes due 2031	400		—
Total debt, net	6,641		6,248
Less: current maturities of long-term debt	—		10
Total long-term debt	$	6,641	$	6,238

(1) 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, 2023, excluding debt issuance costs, premiums and discounts and the unamortized basis adjustment of dedesignated interest rate swap agreements are as follows:


Year Ending December 31,
	(In millions)
2024	$	—
2025	—
2026	764
2027	430
2028	336
Thereafter	5,260
Total	$	6,790

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

Schedule of Interest Expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2023, 2022 and 2021:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Interest expense	$	346	$	272	$	277
Other fees and expenses	2		12		11
Less: interest income	2		1		1
Less: capitalized interest	171		124		88
Interest expense, net	$	175	$	159	$	199

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481568/470-20-55-69B

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69E
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481568/470-20-55-69E

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
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+ Details

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Change in Ownership of Consolidated Subsidiaries (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to Diamondback Energy, Inc.	$ 3,143	$ 4,386	$ 2,182
Change in ownership of consolidated subsidiaries, net	(24)	12	(19)
Subsidiaries
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to Diamondback Energy, Inc.	3,143	4,386	2,182
Change in ownership of consolidated subsidiaries, net	77	(46)	66
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest	$ 3,220	$ 4,340	$ 2,248

- Definition

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

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+ Details

COMMITMENTS AND CONTINGENCIES - Narrative (Details) - Environmental Matters	12 Months Ended
	Dec. 31, 2023 lawsuit
Loss Contingencies [Line Items]
Number of lawsuits	43
Number of lawsuits company is defendant	3

SEGMENT INFORMATION - Summary of Business Segments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Total revenues	$ 8,412	$ 9,643	$ 6,797
Depreciation, depletion, amortization and accretion	1,746	1,344	1,275
Income (loss) from operations	4,570	6,508	4,001
Interest expense, net	(175)	(159)	(199)
Other income (expense)	(195)	(690)	(910)
Income (loss) from equity investments	48	77	15
Provision for (benefit from) income taxes	912	1,174	631
Net income (loss) attributable to non-controlling interest	193	176	94
Net income (loss) attributable to Diamondback Energy, Inc.	3,143	4,386	2,182
Total assets	29,001	26,209	22,898
All Other
Segment Reporting Information [Line Items]
Total revenues	397	440	421
Operating Segments \| Upstream
Segment Reporting Information [Line Items]
Total revenues	8,344	9,572	6,747
Depreciation, depletion, amortization and accretion	1,707	1,279	1,219
Income (loss) from operations	4,519	6,432	3,879
Interest expense, net	(176)	(130)	(167)
Other income (expense)	(268)	(653)	(925)
Income (loss) from equity investments	(1)	0	0
Provision for (benefit from) income taxes	888	1,165	620
Net income (loss) attributable to non-controlling interest	193	150	57
Net income (loss) attributable to Diamondback Energy, Inc.	2,993	4,334	2,110
Total assets	28,362	24,452	21,329
Operating Segments \| All Other
Segment Reporting Information [Line Items]
Total revenues	68	71	50
Depreciation, depletion, amortization and accretion	39	65	56
Income (loss) from operations	129	166	180
Interest expense, net	1	(29)	(32)
Other income (expense)	88	(21)	23
Income (loss) from equity investments	49	77	15
Provision for (benefit from) income taxes	24	9	11
Net income (loss) attributable to non-controlling interest	0	26	37
Net income (loss) attributable to Diamondback Energy, Inc.	243	158	138
Total assets	1,242	2,213	1,942
Eliminations
Segment Reporting Information [Line Items]
Total revenues	(329)	(369)	(371)
Depreciation, depletion, amortization and accretion	0	0	0
Income (loss) from operations	(78)	(90)	(58)
Interest expense, net	0	0	0
Other income (expense)	(15)	(16)	(8)
Income (loss) from equity investments	0	0	0
Provision for (benefit from) income taxes	0	0	0
Net income (loss) attributable to non-controlling interest	0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.	(93)	(106)	(66)
Total assets	$ (603)	$ (456)	$ (373)

INCOME TAXES

12 Months Ended

Dec. 31, 2023

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, and Rattler LLC, file a U.S. federal corporate income tax return on a consolidated basis. As discussed further below, Viper became a taxable entity for U.S. federal income tax purposes effective May 10, 2018, and as such files a U.S. federal corporate income tax return including the activity of its investment in Viper LLC. Viper’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.

For periods subsequent to the Effective Date of the Rattler Merger, Rattler is a member of the group filing consolidated income tax returns with Diamondback Energy, Inc. and its subsidiaries. As such, Rattler’s current and deferred income taxes continue to be included in the Company’s consolidated income tax expense from continuing operations and, only for periods prior to the Rattler Merger, in net income attributable to the non-controlling interest.

The Company’s effective income tax rates were 21.5%, 20.5% and 21.7% for the years ended December 31, 2023, 2022 and 2021, respectively. Total income tax expense for the year ended December 31, 2023 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income primarily due to state income taxes, net of federal benefit, partially offset by the impact of permanent differences between book and taxable income and tax benefit resulting from a reduction in the valuation allowance on Viper’s deferred tax assets for the year ended December 31, 2023. Total income tax expense for the year ended December 31, 2022 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income for the period primarily due to (i) state income taxes, net of federal benefit, partially offset by (ii) the impact of permanent differences between book and taxable income and (iii) tax benefit resulting from a reduction in the valuation allowance on Viper’s and QEP’s deferred tax assets for the year ended December 31, 2022. Total income tax expense for the year ended December 31, 2021 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income for the period primarily due to state income taxes, net of federal benefit.

The Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, which created a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion of average adjusted pre-tax net income on their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock/unit repurchases for tax years beginning after December 31, 2022. Based on application of currently available guidance, the Company’s income tax expense for the year ended December 31, 2023 was not impacted by the CAMT. The Company’s excise tax during the year ended December 31, 2023 was immaterial and was recognized as part of the cost basis of the units repurchased.

The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2023, 2022 and 2021 are as follows:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Current income tax provision (benefit):
Federal	$	505	$	421	$	10
State	29		33		15
Total current income tax provision (benefit)	534		454		25
Deferred income tax provision (benefit):
Federal	370		706		594
State	8		14		12
Total deferred income tax provision (benefit)	378		720		606
Total provision for (benefit from) income taxes	$	912	$	1,174	$	631

A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Income tax expense (benefit) at the federal statutory rate (21%)	$	892	$	1,205	$	610


State income tax expense, net of federal tax effect	31		42		23
Non-deductible compensation	8		10		10
Change in valuation allowance	(7)		(71)		(12)
Other, net	(12)		(12)		—
Provision for (benefit from) income taxes	$	912	$	1,174	$	631

The components of the Company’s deferred tax assets and liabilities as of December 31, 2023 and 2022 are as follows:


	December 31,
	2023		2022
	(In millions)












Deferred tax assets:
Net operating loss and other carryforwards	$	236	$	406
Derivative instruments	22		—
Stock based compensation	7		5

Viper's investment in Viper LLC	170		148
Rattler's investment in Rattler LLC	—		1
Other	21		16
Deferred tax assets	456		576
Valuation allowance	(233)		(223)
Deferred tax assets, net of valuation allowance	223		353
Deferred tax liabilities:
Oil and natural gas properties and equipment	2,463		2,109
Midstream investments	162		235
Derivative instruments	—		12

Other	2		2
Total deferred tax liabilities	2,627		2,358
Net deferred tax liabilities	$	2,404	$	2,005

The Company had net deferred tax liabilities of approximately $2.4 billion and $2.0 billion at December 31, 2023 and 2022, respectively.

At December 31, 2023, the Company had approximately $369 million of federal NOLs and $4 million of federal tax credits expiring in 2037 and $221 million of federal NOLs with an indefinite carryforward life, including NOLs acquired from QEP and from Rattler. 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 and Rattler, are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), 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 of the Code will not have an adverse effect on future usage of the Company’s NOLs and credits.

On August 24, 2022, the Company completed the Rattler Merger. Management considered the likelihood that the federal net operating losses and other tax attributes acquired from Rattler will be utilized, including in light of Rattler’s inclusion in consolidated income tax returns with Diamondback for periods subsequent to the Rattler Merger, and in light of the annual limitation on utilization of tax attributes following Rattler’s ownership change pursuant to Section 382 of the Code. As a result of the assessment, including consideration of all available positive and negative evidence, management determined that it continues to be more likely than not that Rattler will realize its deferred tax assets as of December 31, 2023.

As of December 31, 2023, the Company had a valuation allowance of $11 million related to federal NOL and credit carryforwards acquired from QEP which are estimated not more likely than not to be realized prior to expiration. In addition, the Company had a valuation allowance of $107 million primarily related to certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate significant future operations in those states and a valuation allowance of $114 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 and the limitations imposed by Section 382 of the Code on certain of the Company’s NOLs and other carryforwards. Management believes that the balance of the Company’s NOLs is 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, 2023, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

At December 31, 2023, the Company’s net deferred tax liabilities include deferred tax assets of approximately $170 million related to Viper’s investment in Viper LLC. 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, 2023, Viper had a valuation allowance of approximately $114 million related to deferred tax assets that Viper does not believe are more likely than not to be realized. During the years ended December 31, 2023 and 2022, Viper recognized deferred income tax benefit of $7 million and $50 million, respectively, related to a reduction in its valuation allowance, based on a change in judgment about the realizability of its deferred tax assets. 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, resulted in recognition of tax benefit for the portion of Viper’s deferred tax assets considered more likely than not to be realized. The positive evidence assessed included recent cumulative income due in part to higher commodity prices and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. Viper retained a partial valuation allowance on its deferred tax assets due in part to potential future volatility in commodity prices impacting the likelihood of future realizability.

The following table sets forth changes in the Company’s unrecognized tax benefits:


	December 31,
	2023		2022
	(In millions)
Balance at beginning of year	$	7	$	7


Decrease resulting from expiration of statute	(7)		—

Balance at end of year	—		7
Less: Effects of temporary items	—		(4)
Total that, if recognized, would impact the effective income tax rate as of the end of the year	$	—	$	3

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 the years ended December 31, 2020 through December 31, 2022 remain open for all purposes of examination by the IRS and major state taxing jurisdictions. However, certain earlier tax years remain open for adjustment to the extent of their NOL carryforwards available for future utilization. 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 recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2023 and 2022, there was an insignificant amount of interest and no penalties related to each period associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480990/946-20-50-13

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 17
-Subparagraph (b)
-Publisher FASB
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
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-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482603/740-30-50-2

+ Details

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Acquisition costs:
Proved properties	$ 1,314	$ 778	$ 2,805
Unproved properties	1,701	1,536	1,829
Development costs	1,962	566	516
Exploration costs	768	1,698	1,223
Total	$ 5,745	$ 4,578	$ 6,373

EQUITY-BASED COMPENSATION - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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	$ 26	$ 21	$ 20
General and administrative expenses
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
General and administrative expenses	$ 54	$ 55	$ 51

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS - Income (Loss) of Equity Method Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	$ 48	$ 77	$ 15
EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	(8)	(7)	(16)
Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	3	22	16
Wink to Webster Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	9	4	(3)
OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	17	14	12
WTG joint venture
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	26	44	6
Deep Blue Midland Basin LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	2	0	0
Other
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments, net	$ (1)	$ 0	$ 0

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2023
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Fourth Quarter 2023 Dividend Declaration On February 11, 2024, the board of directors of the Company approved an increase in the Company’s annual base dividend to $3.60 per share of common stock and, on February 16, 2024, the board of directors of the Company declared a cash dividend for the fourth quarter of 2023 of $3.08 per share of common stock, payable on March 12, 2024 to its stockholders of record at the close of business on March 5, 2024. The dividend consists of a base quarterly dividend of $0.90 per share of common stock and a variable quarterly dividend of $2.18 per share of common stock. Future base and variable dividends are at the discretion of the board of directors of the Company. Beginning in the first quarter of 2024, the Company will reduce its return of capital commitment to at least 50% from 75% of its quarterly free cash flow. Pending Endeavor Acquisition On February 11, 2024, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”), by and among the Company, Eclipse Merger Sub I, LLC, Eclipse Merger Sub II, LLC, Endeavor Manager, LLC (solely for purposes of certain sections set forth therein), and Endeavor Parent, LLC (“Endeavor”), to acquire Endeavor (such acquisition, the “Endeavor Acquisition”) for consideration consisting of a base cash amount of $8.0 billion, subject to adjustments under the terms of the Merger Agreement, and approximately 117.27 million shares of the Company’s common stock. The Endeavor Acquisition is expected to close in the fourth quarter of 2024, subject to the satisfaction or waiver of certain customary closing conditions, including the approval of the issuance of the Company’s common stock in the Endeavor Acquisition by the Company’s stockholders and the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. As a result of the Endeavor Acquisition, equityholders of Endeavor are expected to hold, at closing, approximately 39.5% of the outstanding Company common stock. If the Merger Agreement is terminated under certain circumstances, the Company may be required to pay a termination fee of $1.4 billion, including if the proposed Merger Agreement is terminated because the Company’s board of directors has changed its recommendation in respect of the stockholder proposal relating to approval of the issuance of the Company common stock in the Endeavor Acquisition. Additionally, if the Merger Agreement is terminated because the Company’s stockholders fail to approve the issuance of the Company’s common stock in the Endeavor Acquisition and the termination fee is not payable in connection with such termination, the Company is required to reimburse Endeavor for its transaction related expenses, subject to a cap of $260 million. The payment of this reimbursement will reduce any termination fee that is subsequently payable by the Company. On February 11, 2024, in connection with the execution of the Merger Agreement, the Company entered into a commitment letter with Citigroup Global Markets Inc. (“Citi”) pursuant to which Citi committed to provide an $8.0 billion senior unsecured bridge facility, subject to customary conditions. The Company expects to replace such commitment with permanent debt financing prior to the closing of the Endeavor Acquisition.

DEBT - Viper's Credit Agreement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Sep. 22, 2023	May 31, 2023	May 30, 2023
Line of Credit Facility [Line Items]
Long-term debt, gross	$ 6,641	$ 6,248
Viper revolving credit facility
Line of Credit Facility [Line Items]
Commitment amount				$ 850
Viper revolving credit facility \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity					$ 2,000
Current borrowing base				$ 1,300
Remaining borrowing capacity	$ 587
Weighted average interest rate	7.41%	4.22%	2.35%
Viper revolving credit facility \| SOFR \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.10%
Viper revolving credit facility \| Federal Funds Rate \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Viper revolving credit facility \| 1-month Adjusted Term SOFR \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Viper revolving credit facility \| Minimum \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Commitment fee percentage based on unused portion of borrowing base	0.375%
Viper revolving credit facility \| Minimum \| SOFR \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%
Viper revolving credit facility \| Minimum \| Base Rate \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Viper revolving credit facility \| Maximum \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Commitment fee percentage based on unused portion of borrowing base	0.50%
Viper revolving credit facility \| Maximum \| SOFR \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Basis spread on variable rate	3.00%
Viper revolving credit facility \| Maximum \| Base Rate \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%
Viper revolving credit facility \| Viper
Line of Credit Facility [Line Items]
Current borrowing base					1,000	$ 580
Commitment amount					$ 750	$ 500

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

Common Stock Repurchase Programs

The Company’s board of directors has approved a common stock repurchase program to acquire up to $4.0 billion of the Company’s outstanding common stock, excluding excise tax. 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 years ended December 31, 2023, 2022 and 2021, the Company repurchased, excluding excise tax, approximately $838 million, $1.1 billion and $431 million, respectively, of common stock under the respective repurchase programs. As of December 31, 2023, $1.6 billion remained available for use to repurchase shares under the Company’s common stock repurchase program, excluding excise tax.

Change in Ownership of Consolidated Subsidiaries

Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler through the Effective Date of the Rattler Merger and are presented as a component of equity. The Company’s ownership percentages in Viper and Rattler have historically changed 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 their units. These changes in ownership percentage and the disproportionate allocation of net income to the Company result in adjustments to non-controlling interest and additional paid-in-capital, tax effected, but do not impact earnings.

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the respective periods:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Net income (loss) attributable to the Company	$	3,143	$	4,386	$	2,182
Change in ownership of consolidated subsidiaries	77		(46)		66
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest	$	3,220	$	4,340	$	2,248

Dividends

The following table presents dividends and distribution equivalent rights paid on the Company’s common stock during the respective periods:


	Base		Variable		Total		Total
	(In per share)						(In millions)
2023
First quarter	$	0.80	$	2.15	$	2.95	$	546
Second quarter	0.80		0.03		0.83		151
Third quarter	0.84		—		0.84		151
Fourth quarter	0.84		2.53		3.37		607
Total year-to-date	$	3.28	$	4.71	$	7.99	$	1,455

2022
First quarter	$	0.60	$	—	$	0.60	$	108
Second quarter	0.70		2.35		3.05		548
Third quarter	0.75		2.30		3.05		532
Fourth quarter	0.75		1.51		2.26		400
Total year-to-date	$	2.80	$	6.16	$	8.96	$	1,588

2021
First quarter	$	0.40	$	—	$	0.40	$	69
Second quarter	0.40		—		0.40		74
Third quarter	0.45		—		0.45		83
Fourth quarter	0.50		—		0.50		92
Total year-to-date	$	1.75	$	—	$	1.75	$	318

Viper’s Common Stock Repurchase Program

Viper’s board of directors has currently approved a common stock repurchase program to acquire up to $750 million of Viper’s outstanding Class A common stock, excluding excise tax, over an indefinite period of time. During the years ended December 31, 2023, 2022 and 2021, Viper repurchased approximately $95 million, $151 million, and $46 million under its repurchase program. As of December 31, 2023, $434 million remained available for use to repurchase shares under Viper’s common stock repurchase program.

Dividends to Non-Controlling Interest

During the years ended December 31, 2023, 2022 and 2021 Viper paid $129 million, $182 million, and $76 million of distributions and dividends to its public shareholders, excluding Diamondback, in accordance with the dividend policy approved by its board of directors. Prior to the Rattler Merger, Rattler made $35 million and $36 million of distributions to its common unitholders during the years ended December 31, 2022 and 2021, respectively, in accordance with the distribution policy approved by its board of directors. These dividends are reflected under the caption “Dividends/distributions to non-controlling interest” on the Company’s consolidated statement of stockholders’ equity and consolidated statements of cash flows.

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 prior to the Effective Date of the Rattler Merger 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,
	2023		2022		2021
	(In millions, except per share amounts)
Net income (loss) attributable to common stock	$	3,143	$	4,386	$	2,182
Less: distributed and undistributed earnings allocated to participating securities(1)	22		42		20
Net income (loss) attributable to common stockholders	$	3,121	$	4,344	$	2,162
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	179,999		176,539		176,643
Effect of dilutive securities:
Weighted-average potential common shares issuable	—		—		—
Diluted weighted average common shares outstanding	179,999		176,539		176,643
Basic net income (loss) attributable to common stock	$	17.34	$	24.61	$	12.24
Diluted net income (loss) attributable to common stock	$	17.34	$	24.61	$	12.24

- Definition

The entire disclosure for equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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+ Details

INCOME TAXES - Narrative (Details) - USD ($)	12 Months Ended
INCOME TAXES - Narrative (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Loss Carryforwards [Line Items]
Effective income tax rate	21.50%	20.50%	21.70%
Net deferred tax liabilities	$ 2,404,000,000	$ 2,005,000,000
Operating loss carryforwards, subject to expiration	369,000,000
Federal tax credits	4,000,000
Operating loss carryforwards, not subject to expiration	221,000,000
Valuation allowance	233,000,000	223,000,000
Deferred tax liability includes deferred tax asset	170,000,000	148,000,000
Tax benefit recognized	(912,000,000)	(1,174,000,000)	$ (631,000,000)
Penalties associated with uncertain tax positions	0	0
Federal NOL and Carryforwards From Acquisition
Operating Loss Carryforwards [Line Items]
Valuation allowance	11,000,000
State NOL
Operating Loss Carryforwards [Line Items]
Valuation allowance	107,000,000
Viper LLC
Operating Loss Carryforwards [Line Items]
Valuation allowance	114,000,000
Tax benefit recognized	$ 7,000,000	$ 50,000,000

SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS (Tables)

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Information Disclosure [Abstract]

Schedule of Supplemental Disclosures of Cash Flow Information


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	(146)	$	(135)	$	(194)
Cash (paid) received for income taxes, net	$	(352)	$	(718)	$	138
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses	$	618	$	520	$	287
Capitalized stock-based compensation	$	26	$	21	$	20
Common stock issued for acquisitions	$	633	$	1,220	$	1,727
Assets contributed in exchange for ownership interest in an equity method investment	$	126	$	—	$	—
Asset retirement obligations acquired	$	8	$	19	$	65

Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions	Total	Viper	Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)	Non-Controlling Interest	Non-Controlling Interest Viper
Balance at beginning of period (in shares) at Dec. 31, 2020			158,088,000
Balance at beginning of period at Dec. 31, 2020	$ 9,804		$ 2	$ 12,656	$ (3,864)	$ 0	$ 1,010
Increase (Decrease) in Stockholders' Equity
Issuance of common units - Viper Energy Partners LP	337						337
Unit-based compensation	11						11
Distribution equivalent rights payments	(6)				(4)		(2)
Stock-based compensation	60			60
Cash paid for tax withholding on vested equity awards	(8)			(6)			(2)
Repurchased shares for share buyback program (in shares)			(4,128,000)
Repurchased shares under buyback program	(431)			(431)
Repurchased shares/units under Viper's buyback programs	(94)						(94)
Common stock issued for acquisitions (in shares)			22,795,000
Common stock issued for acquisition	1,727			1,727
Dividends/distributions to non-controlling interest	(112)						(112)
Dividend paid	(312)				(312)
Exercise of stock options and issuance of restricted stock units and awards (in shares)			796,000
Exercise of stock options and issuance of restricted stock units and awards	12			12
Change in ownership of consolidated subsidiaries, net	(19)			66			(85)
Net income (loss)	2,276				2,182		94
Balance at end of period (in shares) at Dec. 31, 2021			177,551,000
Balance at end of period at Dec. 31, 2021	13,245		$ 2	14,084	(1,998)	0	1,157
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	8						8
Distribution equivalent rights payments	(16)				(15)		(1)
Stock-based compensation (in shares)			4,000
Stock-based compensation	68			68
Cash paid for tax withholding on vested equity awards (in shares)			(11,000)
Cash paid for tax withholding on vested equity awards	(19)			(16)			(3)
Repurchased shares for share buyback program (in shares)			(8,694,000)
Repurchased shares under buyback program	(1,098)			(1,098)
Repurchased shares/units under Viper's buyback programs	(153)						(153)
Common stock issued for acquisitions (in shares)			10,273,000
Common stock issued for acquisition	876			1,220			(344)
Dividends/distributions to non-controlling interest	(217)						(217)
Dividend paid	(1,572)				(1,572)
Exercise of stock options and issuance of restricted stock units and awards (in shares)			718,000
Exercise of stock options and issuance of restricted stock units and awards	1			1
Change in ownership of consolidated subsidiaries, net	12			(46)			58
Other comprehensive income (loss), net of tax	(7)					(7)
Net income (loss)	$ 4,562				4,386		176
Balance at end of period (in shares) at Dec. 31, 2022	179,840,797		179,841,000
Balance at end of period at Dec. 31, 2022	$ 15,690		$ 2	14,213	801	(7)	681
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	1						1
Distribution equivalent rights payments	(11)				(11)
Stock-based compensation (in shares)			394,000
Stock-based compensation	79			79
Cash paid for tax withholding on vested equity awards (in shares)			(146,000)
Cash paid for tax withholding on vested equity awards	(20)			(20)
Repurchased shares for share buyback program (in shares)			(6,238,000)
Repurchased shares under buyback program	(840)			(840)
Repurchased shares/units under Viper's buyback programs	(95)						(95)
Common stock issued for acquisitions (in shares)			4,330,000
Common stock issued for acquisition	633	$ 255		633				$ 255
Dividends/distributions to non-controlling interest	(129)						(129)
Dividend paid	(1,444)				(1,444)
Exercise of stock options and issuance of restricted stock units and awards (in shares)			543,000
Exercise of stock options and issuance of restricted stock units and awards	0
Change in ownership of consolidated subsidiaries, net	(24)			77			(101)
Other comprehensive income (loss), net of tax	(1)					(1)
Net income (loss)	$ 3,336				3,143		193
Balance at end of period (in shares) at Dec. 31, 2023	178,723,871		178,724,000
Balance at end of period at Dec. 31, 2023	$ 17,430		$ 2	$ 14,142	$ 2,489	$ (8)	$ 805

Consolidated Statements of Operations and Comprehensive Income - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Other operating income	$ 73	$ 77	$ 50
Total revenues	8,412	9,643	6,797
Costs and expenses:
Lease operating expenses	872	652	565
Production and ad valorem taxes	525	611	425
Depreciation, depletion, amortization and accretion	1,746	1,344	1,275
General and administrative expenses	150	144	146
Merger and integration expenses	11	14	78
Other operating expenses	140	112	95
Total costs and expenses	3,842	3,135	2,796
Income (loss) from operations	4,570	6,508	4,001
Other income (expense):
Interest expense, net	(175)	(159)	(199)
Other income (expense), net	68	(5)	13
Gain (loss) on derivative instruments, net:	(259)	(586)	(848)
Gain (loss) on extinguishment of debt	(4)	(99)	(75)
Income (loss) from equity investments, net	48	77	15
Total other income (expense), net	(322)	(772)	(1,094)
Income (loss) before income taxes	4,248	5,736	2,907
Provision for (benefit from) income taxes	912	1,174	631
Net income (loss)	3,336	4,562	2,276
Net income (loss) attributable to non-controlling interest	193	176	94
Net income (loss) attributable to Diamondback Energy, Inc.	$ 3,143	$ 4,386	$ 2,182
Earnings (loss) per common share:
Basic (in dollars per share)	$ 17.34	$ 24.61	$ 12.24
Diluted (in dollars per share)	$ 17.34	$ 24.61	$ 12.24
Weighted average common shares outstanding:
Basic (in shares)	179,999	176,539	176,643
Diluted (in shares)	179,999	176,539	176,643
Comprehensive income (loss):
Net income (loss) attributable to Diamondback Energy, Inc.	$ 3,143	$ 4,386	$ 2,182
Other comprehensive income (loss), net of tax:
Pension and postretirement benefit plans	(1)	(7)	0
Comprehensive income (loss) attributable to Diamondback Energy, Inc	3,142	4,379	2,182
Oil sales
Revenues:
Revenues	7,279	7,660	5,396
Natural gas sales
Revenues:
Revenues	262	858	569
Natural gas liquid sales
Revenues:
Revenues	687	1,048	782
Sales of purchased oil
Revenues:
Revenues	111	0	0
Costs and expenses:
Cost of goods and services sold	111	0	0
Gathering, processing and transportation
Costs and expenses:
Cost of goods and services sold	$ 287	$ 258	$ 212

REVENUE FROM CONTRACTS WITH CUSTOMERS - Concentrations (Details) - Customer Concentration Risk - Revenue Benchmark	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Vitol Inc
Concentration Risk [Line Items]
Concentration risk, percentage	22.00%	23.00%	21.00%
DK Trading & Supply LLC
Concentration Risk [Line Items]
Concentration risk, percentage	18.00%
Shell Trading US Company
Concentration Risk [Line Items]
Concentration risk, percentage	14.00%	20.00%	19.00%
Enterprise Crude Oil LLC
Concentration Risk [Line Items]
Concentration risk, percentage	13.00%
Plains Marketing LP
Concentration Risk [Line Items]
Concentration risk, percentage			12.00%

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 582	$ 157
Restricted cash	3	7
Accounts receivable:
Joint interest and other, net	192	104
Oil and natural gas sales, net	654	618
Income tax receivable	1	284
Inventories	63	67
Derivative instruments	17	132
Prepaid expenses and other current assets	109	23
Total current assets	1,621	1,392
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,659 million and $8,355 million excluded from amortization at December 31, 2023 and December 31, 2022, respectively)	42,430	37,122
Other property, equipment and land	673	1,481
Accumulated depletion, depreciation, amortization and impairment	(16,429)	(14,844)
Property and equipment, net	26,674	23,759
Funds held in escrow	0	119
Equity method investments	529	566
Assets held for sale	0	158
Derivative instruments	1	23
Deferred income taxes, net	45	64
Investment in real estate, net	84	86
Other assets	47	42
Total assets	29,001	26,209
Current liabilities:
Accounts payable - trade	261	127
Accrued capital expenditures	493	480
Current maturities of long-term debt	0	10
Other accrued liabilities	475	399
Revenues and royalties payable	764	619
Derivative instruments	86	47
Income taxes payable	29	34
Total current liabilities	2,108	1,716
Long-term debt	6,641	6,238
Derivative instruments	122	148
Asset retirement obligations	239	336
Deferred income taxes	2,449	2,069
Other long-term liabilities	12	12
Total liabilities	11,571	10,519
Commitments and contingencies (Note 15)
Stockholders’ equity:
Common stock, $0.01 par value; 400,000,000 shares authorized; 178,723,871 and 179,840,797 shares issued and outstanding at December 31, 2023 and December 31, 2022, respectively	2	2
Additional paid-in capital	14,142	14,213
Retained earnings (accumulated deficit)	2,489	801
Accumulated other comprehensive income (loss)	(8)	(7)
Total Diamondback Energy, Inc. stockholders’ equity	16,625	15,009
Non-controlling interest	805	681
Total equity	17,430	15,690
Total liabilities and stockholders' equity	$ 29,001	$ 26,209

ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2023

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,
	2023		2022
	(In millions)
Asset retirement obligations, beginning of period	$	347	$	171
Additional liabilities incurred	4		36
Liabilities acquired	8		19
Liabilities settled and divested	(88)		(26)
Accretion expense	16		14
Revisions in estimated liabilities(1)	(42)		133
Asset retirement obligations, end of period	245		347
Less: current portion(2)	6		11
Asset retirement obligations - long-term	$	239	$	336

(1) Revisions in estimated liabilities for the year ended December 31, 2023 are primarily the result of changes in estimated future plugging and abandonment costs due to reductions in current cost estimates and other factors.

(2) The current portion of the asset retirement obligation is included in the caption “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.

SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Information Disclosure [Abstract]

SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	(146)	$	(135)	$	(194)
Cash (paid) received for income taxes, net	$	(352)	$	(718)	$	138
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses	$	618	$	520	$	287
Capitalized stock-based compensation	$	26	$	21	$	20
Common stock issued for acquisitions	$	633	$	1,220	$	1,727
Assets contributed in exchange for ownership interest in an equity method investment	$	126	$	—	$	—
Asset retirement obligations acquired	$	8	$	19	$	65

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS - Distributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Distributions from equity method investments	$ 36	$ 52	$ 44
Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Distributions from equity method investments	0	28	26
Wink to Webster Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Distributions from equity method investments	13	5	0
OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Distributions from equity method investments	$ 23	$ 19	$ 18

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Standardized measure of discounted future net cash flows at the beginning of the period	$ 35,699	$ 18,717	$ 6,758
Sales of oil and natural gas, net of production costs	(6,544)	(8,045)	(5,757)
Acquisitions of reserves	1,854	1,473	1,914
Divestitures of reserves	(938)	(119)	(275)
Extensions and discoveries, net of future development costs	5,771	7,674	6,298
Previously estimated development costs incurred during the period	1,180	823	548
Net changes in prices and production costs	(17,276)	17,785	10,748
Changes in estimated future development costs	518	(317)	(19)
Revisions of previous quantity estimates	(1,268)	102	719
Accretion of discount	4,533	2,183	703
Net change in income taxes	2,506	(4,904)	(2,841)
Net changes in timing of production and other	1,023	327	(79)
Standardized measure of discounted future net cash flows at the end of the period	$ 27,058	$ 35,699	$ 18,717

SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
SEGMENT INFORMATION - Additional Information (Details)	Dec. 31, 2023 segment
Segment Reporting [Abstract]
Number of reportable segments	1

Cover - USD ($) $ in Billions	12 Months Ended
Cover - USD ($) $ in Billions	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-35700
Entity Registrant Name	Diamondback Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	45-4502447
Entity Address, Address Line One	500 West Texas
Entity Address, Address Line Two	Suite 100
Entity Address, City or Town	Midland,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	79701
City Area Code	432
Local Phone Number	221-7400
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	FANG
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 23.4
Entity Common Stock, Shares Outstanding		178,446,583
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2024 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001539838

FAIR VALUE MEASUREMENTS - Asset and Liabilities Not Recorded at Fair Value (Details) - Nonrecurring - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Carrying Value
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt	$ 6,641	$ 6,248
Fair Value
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt	$ 6,507	$ 5,754

PROPERTY AND EQUIPMENT - Schedule of Property and equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and natural gas properties:
Subject to depletion	$ 33,771	$ 28,767
Not subject to depletion	8,659	8,355
Gross oil and natural gas properties	42,430	37,122
Accumulated depletion and depreciation	(16,429)	(14,844)
Accumulated impairment	(7,954)	(7,954)
Oil and natural gas properties, net	26,143	22,497
Other property, equipment and land	673	1,481
Property and equipment, net	26,674	23,759
Oil and Gas Properties
Oil and natural gas properties:
Subject to depletion	33,771	28,767
Not subject to depletion	8,659	8,355
Gross oil and natural gas properties	42,430	37,122
Accumulated depletion and depreciation	(8,333)	(6,671)
Accumulated impairment	(7,954)	(7,954)
Oil and natural gas properties, net	26,143	22,497
Balance of costs not subject to depletion	1,470	827	$ 1,136
Prior				$ 5,226
Other Property and Equipment, Net
Oil and natural gas properties:
Accumulated depletion and depreciation	(142)	(219)
Other property, equipment and land	$ 673	$ 1,481

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 01, 2023 county
Equity Method Investments and Related Party Transactions [Abstract]
Equity method investment impairment	$ 0	$ 0	$ 0
Number of counties \| county				12
Water Services Agreement
Related Party Transaction [Line Items]
Related party transaction amounts	$ 35,000,000

SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2023

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		All Other		Eliminations		Total
	(In millions)
Year Ended December 31, 2023:
Third-party revenues	$	8,344	$	68	$	—	$	8,412
Intersegment revenues	—		329		(329)		—
Total revenues	$	8,344	$	397	$	(329)	$	8,412
Depreciation, depletion, amortization and accretion	$	1,707	$	39	$	—	$	1,746

Income (loss) from operations	$	4,519	$	129	$	(78)	$	4,570
Interest expense, net	$	(176)	$	1	$	—	$	(175)
Other income (expense)	$	(268)	$	88	$	(15)	$	(195)
Income (loss) from equity investments	$	(1)	$	49	$	—	$	48
Provision for (benefit from) income taxes	$	888	$	24	$	—	$	912
Net income (loss) attributable to non-controlling interest	$	193	$	—	$	—	$	193
Net income (loss) attributable to Diamondback Energy, Inc.	$	2,993	$	243	$	(93)	$	3,143
Total assets	$	28,362	$	1,242	$	(603)	$	29,001


	Upstream		All Other		Eliminations		Total
	(In millions)
Year Ended December 31, 2022:
Third-party revenues	$	9,572	$	71	$	—	$	9,643
Intersegment revenues	—		369		(369)		—
Total revenues	$	9,572	$	440	$	(369)	$	9,643
Depreciation, depletion, amortization and accretion	$	1,279	$	65	$	—	$	1,344

Income (loss) from operations	$	6,432	$	166	$	(90)	$	6,508
Interest expense, net	$	(130)	$	(29)	$	—	$	(159)
Other income (expense)	$	(653)	$	(21)	$	(16)	$	(690)
Income (loss) from equity investments	$	—	$	77	$	—	$	77
Provision for (benefit from) income taxes	$	1,165	$	9	$	—	$	1,174
Net income (loss) attributable to non-controlling interest	$	150	$	26	$	—	$	176
Net income (loss) attributable to Diamondback Energy, Inc.	$	4,334	$	158	$	(106)	$	4,386
Total assets	$	24,452	$	2,213	$	(456)	$	26,209


	Upstream		All Other		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)	$	23	$	(8)	$	(910)
Income (loss) from equity investments	$	—	$	15	$	—	$	15
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

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Stock Repurchase Programs, Viper Issuance of Common Units to Diamondback Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Stock repurchase program authorized amount	$ 4,000,000,000
Treasury Stock acquired	838,000,000	$ 1,100,000,000	$ 431,000,000
Stock repurchase remaining authorized amount	$ 1,600,000,000

EQUITY-BASED COMPENSATION - Restricted Stock Units - Narrative (Details) - Restricted Stock Units (RSUs) - Equity Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregated fair value of restricted stock	$ 48	$ 41	$ 46
Share based award not recognized	$ 74
Unrecognized compensation cost, expected period of recognition	1 year 10 months 24 days

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables present the Company’s revenue from contracts with customers:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Oil sales	$	7,279	$	7,660	$	5,396
Natural gas sales	262		858		569
Natural gas liquid sales	687		1,048		782
Total oil, natural gas and natural gas liquid revenues	8,228		9,566		6,747
Sales of purchased oil	111		—		—
Midstream and marketing services	62		69		45
Total revenue from contracts with customers	$	8,401	$	9,635	$	6,792

The following tables present the Company’s revenue from oil, natural gas, and natural gas liquids disaggregated by basin:


	Year Ended December 31, 2023
	Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	5,746	$	1,527	$	6	$	7,279
Natural gas sales	176		85		1		262
Natural gas liquid sales	500		187		—		687
Total	$	6,422	$	1,799	$	7	$	8,228


	Year Ended December 31, 2022
	Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	5,541	$	2,107	$	12	$	7,660
Natural gas sales	563		292		3		858
Natural gas liquid sales	719		327		2		1,048
Total	$	6,823	$	2,726	$	17	$	9,566


	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

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Feb. 16, 2024	Feb. 11, 2024	Mar. 31, 2024	Dec. 31, 2023
Subsequent Event [Line Items]
Return of capital commitment				75.00%
Forecast
Subsequent Event [Line Items]
Return of capital commitment			50.00%
Subsequent Event
Subsequent Event [Line Items]
Dividends declared per share (in dollars per share)	$ 3.08
Subsequent Event \| Endeavor Acquisition
Subsequent Event [Line Items]
Expected acquisition price		$ 8,000
Number of shares issuable (in shares)		117,270
Contract termination fee		$ 1,400
Contingent reimbursement fees		$ 260
Subsequent Event \| Endeavor \| Endeavor Acquisition
Subsequent Event [Line Items]
Ownership percentage by noncontrolling parties		39.50%
Subsequent Event \| Senior Unsecured Bridge Facility \| Endeavor Acquisition
Subsequent Event [Line Items]
Maximum borrowing capacity		$ 8,000
Subsequent Event \| Base
Subsequent Event [Line Items]
Dividends declared per share (in dollars per share)		$ 3.60
Dividends payable (usd per share)	0.90
Subsequent Event \| Variable
Subsequent Event [Line Items]
Dividends payable (usd per share)	$ 2.18

DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2023, 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 Floor Price	Weighted Average Ceiling Price
OIL
Jan. - Jun.	2024	Costless Collar	6,000	WTI Cushing	$—		$65.00	$95.55
Jan. - Dec.	2024	Basis Swap(1)	10,000	Argus WTI Midland	$1.19		$—	$—
Jan. - Dec.	2024	Roll Swap	30,000	WTI	$0.81		$—	$—
Jul. - Dec.	2024	Costless Collar	4,000	WTI Cushing	$—		$55.00	$93.66
NATURAL GAS
Jan. - Dec.	2024	Costless Collar	290,000	Henry Hub	$—		$2.83	$7.52
Jan. - Dec.	2024	Basis Swap(1)	380,000	Waha Hub	$(1.18)		$—	$—
Jan. - Dec.	2025	Basis Swap(1)	310,000	Waha Hub	$(0.69)		$—	$—

(1) 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	Deferred Premium
OIL
Jan. - Mar.	2024	Put	124,000	Brent	$55.40	$1.48
Jan. - Mar.	2024	Put	32,000	Argus WTI Houston	$55.00	$1.60
Jan. - Mar.	2024	Put	16,000	WTI Cushing	$58.13	$1.54
Apr. - Jun.	2024	Put	108,000	Brent	$55.46	$1.49
Apr. - Jun.	2024	Put	26,000	Argus WTI Houston	$55.00	$1.56
Apr. - Jun.	2024	Put	14,000	WTI Cushing	$59.29	$1.51
Jul. - Sep.	2024	Put	66,000	Brent	$55.15	$1.53
Jul. - Sep.	2024	Put	18,000	Argus WTI Houston	$55.00	$1.55
Jul. - Sep.	2024	Put	2,000	WTI Cushing	$55.00	$1.53
Oct. - Dec.	2024	Put	34,000	Brent	$55.00	$1.61
Oct. - Dec.	2024	Put	4,000	Argus WTI Houston	$55.00	$1.72
Oct. - Dec.	2024	Put	2,000	WTI Cushing	$55.00	$1.53

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,
	2023		2022		2021
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	(239)	$	(528)	$	(978)
Interest rate swaps	(20)		(58)		130
Total	$	(259)	$	(586)	$	(848)

Net cash received (paid) on settlements:
Commodity contracts(1)	$	(61)	$	(849)	$	(1,305)
Interest rate swaps(2)	(49)		(1)		80
Total	$	(110)	$	(850)	$	(1,225)

(1)The years ended December 31, 2022 and 2021 include cash paid on commodity contracts terminated prior to their contractual maturity of $138 million and $16 million, respectively.

(2)The year ended December 31, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

- Definition

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.

+ References + Details

DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION (Details) $ / shares in Units, $ in Thousands					12 Months Ended
	Nov. 13, 2023 shares	Nov. 01, 2023 USD ($)	Oct. 31, 2023 USD ($) $ / shares shares	Aug. 24, 2022 USD ($) shares	Dec. 31, 2023 USD ($) segment shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares
Business Acquisition [Line Items]
Common stock issued for acquisition					$ 633,000	$ 876,000	$ 1,727,000
Merger and integration expenses					$ 11,000	$ 14,000	$ 78,000
Shares converted (in shares) \| shares	1
Number of common units sold (in shares) \| shares			7,220,000
Sale of stock (usd per share) \| $ / shares			$ 27.72
Consideration received on transaction		$ 200,000	$ 200,000
Number of business segments \| segment					2
Common Class B
Business Acquisition [Line Items]
Shares converted (in shares) \| shares	1
Common Stock
Business Acquisition [Line Items]
Common stock issued for acquisitions (in shares) \| shares				4,350,000	4,330,000	10,273,000	22,795,000
Additional Paid-in Capital
Business Acquisition [Line Items]
Common stock issued for acquisition					$ 633,000	$ 1,220,000	$ 1,727,000
Non-Controlling Interest
Business Acquisition [Line Items]
Common stock issued for acquisition						$ (344,000)
Rattler Midstream Partners, LP
Business Acquisition [Line Items]
Shares acquired (in shares) \| shares				38,510,000
Noncash increases to common stock				$ 44
Merger and integration expenses				11,000
Rattler Midstream Partners, LP \| Additional Paid-in Capital
Business Acquisition [Line Items]
Common stock issued for acquisition				344,000
Rattler Midstream Partners, LP \| Non-Controlling Interest
Business Acquisition [Line Items]
Common stock issued for acquisition				$ 344,000
Viper
Business Acquisition [Line Items]
Common stock issued for acquisition					$ 255,000
Ownership percentage					56.00%
Viper \| Non-Controlling Interest
Business Acquisition [Line Items]
Common stock issued for acquisition					$ 255,000

COMMITMENTS AND CONTINGENCIES - Commitments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Water Services Agreement
Supply Commitment [Line Items]
Produced water disposal services term	14 years
Sand Supply Agreement
Supply Commitment [Line Items]
2024	$ 26
2025	22
2026	18
2027	4
2028	0
Thereafter	0
Total	70
Transportation Commitments
Supply Commitment [Line Items]
2024	98
2025	103
2026	109
2027	77
2028	67
Thereafter	314
Total	768
Electrical Fracturing Fleet
Supply Commitment [Line Items]
2024	50
2025	40
2026	3
2027	0
2028	0
Thereafter	0
Total	$ 93
Commitment term	3 years
Produced Water Disposal Commitments
Supply Commitment [Line Items]
2024	$ 5
2025	3
2026	4
2027	4
2028	3
Thereafter	21
Total	40
Electrical Power Agreements
Supply Commitment [Line Items]
2024	72
2025	72
2026	71
2027	70
2028	37
Thereafter	85
Total	$ 407

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2023

Equity Method Investments and Related Party Transactions [Abstract]

Equity Method Investments

At December 31, 2023 and 2022, the Company had the following significant equity method investments:


	Ownership Interest		December 31, 2023		December 31, 2022
			(In millions)
EPIC Crude Holdings, LP	10	%	$	93	$	101
Gray Oak Pipeline, LLC(1)(2)	—	%	—		115
Wink to Webster Pipeline LLC	4	%	92		87
OMOG JV LLC(2)	—	%	—		191
BANGL LLC	10	%	29		28
WTG joint venture	25	%	182		156
Deep Blue Midland Basin LLC	30	%	128		—
Other	various		5		3
Total			$	529	$	681

(1) The Company’s investment of $115 million in Gray Oak was classified in assets held for sale in the consolidated balance sheet at December 31, 2022, and was subsequently divested in January 2023 as further discussed in Note 4—Acquisitions and Div estitures.

(2) The Company’s investment of $190 million in OMOG was divested in July 2023 as further discussed in Note 4—Ac q uisitions and Divestitures.

The following table presents total distributions received from the Company’s equity method investments for the periods indicated:


	Year Ended December 31,
	2023		2022		2021
	(In millions)

Gray Oak Pipeline, LLC	$	—	$	28	$	26
Wink to Webster Pipeline LLC	13		5		—
OMOG JV LLC	23		19		18




Total	$	36	$	52	$	44

The following summarizes the income (loss) of equity method investees for the periods presented:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
EPIC Crude Holdings, LP	$	(8)	$	(7)	$	(16)
Gray Oak Pipeline, LLC	3		22		16
Wink to Webster Pipeline LLC	9		4		(3)
OMOG JV LLC	17		14		12

WTG joint venture	26		44		6

Deep Blue Midland Basin LLC	2		—		—
Other	(1)		—		—
Total	$	48	$	77	$	15

Schedule of Related Party Transactions

The following table presents the significant related party balances included in the consolidated balance sheet at December 31, 2023:


	December 31, 2023

	(In millions)
Current assets - Accounts receivable	$	61
Current liabilities - Accrued capital expenditures	$	(21)
Current liabilities - Other accrued liabilities	$	(18)

During the year ended December 31, 2023, the Company also paid Deep Blue approximately $35 million for water services provided during the completion phase of wells. These costs were capitalized and are included in the caption “Oil and natural gas properties” on the consolidated balance sheet.

The following table presents the significant related party transactions included in the consolidated statement of operations for the year ended December 31, 2023:


	Year Ended December 31, 2023

	(In millions)
Lease operating expenses	$	33


Net income (loss)	$	(33)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Property, Equipment and Land - Additional Information (Details) - Other Property and Equipment, Net	Dec. 31, 2023
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

ACQUISITIONS AND DIVESTITURES - Schedule of Preliminary Purchase Price Allocation (Details) - QEP $ in Millions	Mar. 17, 2021 USD ($)
Business Combination, Consideration Transferred [Abstract]
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	2,922
Other property, equipment and land	16
Deferred income taxes	39
Other assets	106
Amount attributable to assets acquired	3,294
Net assets acquired and liabilities assumed	$ 987

EQUITY-BASED COMPENSATION

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

EQUITY-BASED COMPENSATION

Under the equity incentive plan (the “Equity Plan”), approved by the board of directors, the Company is authorized to issue up to 11.8 million shares of incentive and non-statutory stock options, restricted stock awards and restricted stock units, performance awards and stock appreciation rights to eligible employees. The Company currently has outstanding restricted stock units and performance-based restricted stock units under the Equity Plan. The Company also has immaterial amounts of restricted share awards and stock appreciation rights outstanding which were issued under plans assumed in connection with previously completed mergers. At December 31, 2023, approximately 5.1 million shares of common stock remain available for future grants under the Equity Plan. The Company classifies its restricted stock units and performance-based restricted stock units as equity-based awards and 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.

In addition to the Equity Plan, Viper maintains its own long-term incentive plan, which is not significant to the Company.

The following table presents the financial statement impacts of equity compensation plans and related costs on the Company’s financial statements:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
General and administrative expenses	$	54	$	55	$	51
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	26	$	21	$	20

Restricted Stock Units

The following table presents the Company’s restricted stock unit activity during the year ended December 31, 2023 under the Equity Plan:


	Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2022	918,902	$	95.74
Granted	464,367	$	145.45
Vested	(558,077)	$	85.94
Forfeited	(73,996)	$	108.00
Unvested at December 31, 2023	751,196	$	132.29

The aggregate grant date fair value of restricted stock units that vested during the years ended December 31, 2023, 2022 and 2021 was $48 million, $41 million and $46 million, respectively. As of December 31, 2023, the Company’s unrecognized compensation cost related to unvested restricted stock units was $74 million, which is expected to be recognized over a weighted-average period of 1.9 years.

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 2023, eligible employees received performance restricted stock unit awards totaling 126,347 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, 2023 to December 31, 2025 and cliff vest at December 31, 2025 subject to continued employment. The initial payout of the March 2023 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%. Additionally, in July 2023 the Company granted 1,858 units under substantially the same terms as the March 2023 performance restricted stock unit awards.

In March 2022, eligible employees received performance restricted stock unit awards totaling 126,905 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, 2022 to December 31, 2024 and cliff vest at December 31, 2024 subject to continued employment. The initial payout of the March 2022 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% units could be awarded based upon the TSR during the three-year performance period of January 1, 2021 to December 31, 2023. These awards cliff vested at 250% on December 31, 2023 based upon the results of the TSR during the performance period.

The fair value of each performance restricted stock unit issuance 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 periods presented:


	March 2023			July 2023			2022			2021
Grant-date fair value	$	259.52		$	222.09		$	237.13		$	131.06
Risk-free rate	4.64		%	4.70		%	1.44		%	15.00		%
Company volatility	46.90		%	47.20		%	72.10		%	69.60		%

The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2023:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2022	347,881	$	168.48
Granted	361,268	$	258.98
Vested	(388,436)	$	134.64
Forfeited	(42,657)	$	144.48
Unvested at December 31, 2023(1)	278,056	$	234.80

(1)A maximum of 645,703 units could be awarded based upon the Company’s final TSR ranking.

As of December 31, 2023, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $35 million, which is expected to be recognized over a weighted-average period of 2.0 years.

ACQUISITIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2023

QEP

Asset Acquisition [Line Items]

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

The following table sets forth the Company’s 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	2,922
Other property, equipment and land	16
Deferred income taxes	39
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,
		2023		2022		2021
		(In millions, except per share amounts)
Revenues		$	8,457	$	10,542	$	7,198
Income (loss) from operations		$	4,607	$	7,071	$	4,193
Net income (loss)		$	3,175	$	4,834	$	2,148
Basic earnings per common share		$	17.48	$	25.74	$	11.40
Diluted earnings per common share		$	17.48	$	25.74	$	11.40

Lario Acquisition

Asset Acquisition [Line Items]

Schedule of Asset Acquisition

The following table presents the acquisition consideration paid in the Lario Acquisition (in millions, except per share data, shares in thousands):


Consideration:
Shares of Diamondback common stock issued at closing	4,330
Closing price per share of Diamondback common stock on the closing date	$	146.12
Fair value of Diamondback common stock issued	$	633
Cash consideration	814
Total consideration (including fair value of Diamondback common stock issued)	$	1,447

Schedule of Estimated Fair Values of Assets Acquired and Liabilities Assumed

The following table sets forth the Company’s purchase price allocation (in millions):








Total consideration	$	1,447

Fair value of liabilities assumed:
Other long-term liabilities	37

Fair value of assets acquired:
Oil and natural gas properties	1,460
Inventories	2
Other property, equipment and land	22
Amount attributable to assets acquired	1,484
Net assets acquired and liabilities assumed	$	1,447

Firebird Acquisition

Asset Acquisition [Line Items]

Schedule of Asset Acquisition

The following table presents the acquisition consideration paid in the FireBird Acquisition (in millions, except per share data, shares in thousands):


Consideration:
Shares of Diamondback common stock issued at closing	5,921
Closing price per share of Diamondback common stock on the closing date	$	148.02
Fair value of Diamondback common stock issued	$	876
Cash consideration	787
Total consideration (including fair value of Diamondback common stock issued)	$	1,663

Schedule of Estimated Fair Values of Assets Acquired and Liabilities Assumed

The following table sets forth the Company’s purchase price allocation (in millions):








Total consideration	$	1,663

Fair value of liabilities assumed:
Other long-term liabilities	10

Fair value of assets acquired:
Oil and natural gas properties	1,598
Inventories	3
Other property, equipment and land	72
Amount attributable to assets acquired	1,673
Net assets acquired and liabilities assumed	$	1,663

Guidon Operating LLC

Asset Acquisition [Line Items]

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

Schedule of Acquisition Consideration Paid

The following table sets forth the Company’s 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 natural 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 - Dispositions (Details)							1 Months Ended	12 Months Ended
ACQUISITIONS AND DIVESTITURES - Dispositions (Details)	Jul. 28, 2023 USD ($)	Apr. 28, 2023 USD ($) a	Mar. 31, 2023 USD ($) a	Jan. 09, 2023 USD ($)	Nov. 01, 2021 USD ($)	Oct. 21, 2021 USD ($) a	Oct. 31, 2022 USD ($) a bbl / d Boe	Dec. 31, 2023 USD ($)	Dec. 01, 2021 USD ($)	Jun. 03, 2021 a
Williston Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land \| a						95,000
Asset acquisition, price of acquisition, expected						$ 586,000,000
Rattler’s Gas Gathering
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration due at closing					$ 84,000,000
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					$ 54,000,000
Disposed of by Sale \| Glasscock County Disposition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land, net \| a		19,000
Consideration for divestiture		$ 269,000,000
Gain (loss) on disposal		$ 0
Disposed of by Sale \| Ward and Winkler Counties Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land, net \| a			4,900
Consideration for divestiture			$ 72,000,000
Gain (loss) on disposal			$ 0
Disposed of by Sale \| Non-Core Delaware Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land \| a							3,272
Oil, net production per day \| bbl / d							550
Oil equivalent, net production per day \| Boe							800
Asset acquisition, price of acquisition, expected							$ 155,000,000
Disposed of by Sale \| Permian
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset acquisition, price of acquisition, expected								$ 82,000,000
Disposed of by Sale \| Permian \| Southern Midland Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land \| a										7,000
Disposed of by Sale \| Permian \| Delaware Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Combined tier one acres \| a										1,300
Disposed of by Sale \| Williston Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land \| a						95,000
Gain (loss) on disposition of assets						$ 0
Asset acquisition, price of acquisition, expected						586,000,000
Disposed of by Sale \| 2021 Dropdown Transaction
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Carrying value of assets disposed									$ 164,000,000
Asset acquisition, price of acquisition, expected						$ 164,000,000
OMOG JV LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity method investment, interest sold	43.00%
Proceeds from sale of equity method investments	$ 225,000,000
Gain (loss) on sale of equity method investments								35,000,000
Gray Oak Pipeline, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity method investment, interest sold				10.00%
Proceeds from sale of equity method investments				$ 172,000,000
Gain (loss) on sale of equity method investments								$ 53,000,000

STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE - Dividends (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Dividends [Line Items]
Dividend paid (usd per share)	$ 3.37	$ 0.84	$ 0.83	$ 2.95	$ 2.26	$ 3.05	$ 3.05	$ 0.60	$ 0.50	$ 0.45	$ 0.40	$ 0.40	$ 7.99	$ 8.96	$ 1.75
Dividends	$ 607	$ 151	$ 151	$ 546	$ 400	$ 532	$ 548	$ 108	$ 92	$ 83	$ 74	$ 69	$ 1,455	$ 1,588	$ 318
Base
Dividends [Line Items]
Dividend paid (usd per share)	$ 0.84	$ 0.84	$ 0.80	$ 0.80	$ 0.75	$ 0.75	$ 0.70	$ 0.60	$ 0.50	$ 0.45	$ 0.40	$ 0.40	$ 3.28	$ 2.80	$ 1.75
Variable
Dividends [Line Items]
Dividend paid (usd per share)	$ 2.53	$ 0	$ 0.03	$ 2.15	$ 1.51	$ 2.30	$ 2.35	$ 0	$ 0	$ 0	$ 0	$ 0	$ 4.71	$ 6.16	$ 0

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2023

Equity Method Investments and Related Party Transactions [Abstract]

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS

The Company considers its equity method investees to be related parties. At December 31, 2023 and 2022, the Company had the following significant equity method investments:


	Ownership Interest		December 31, 2023		December 31, 2022
			(In millions)
EPIC Crude Holdings, LP	10	%	$	93	$	101
Gray Oak Pipeline, LLC(1)(2)	—	%	—		115
Wink to Webster Pipeline LLC	4	%	92		87
OMOG JV LLC(2)	—	%	—		191
BANGL LLC	10	%	29		28
WTG joint venture	25	%	182		156
Deep Blue Midland Basin LLC	30	%	128		—
Other	various		5		3
Total			$	529	$	681

(2) The Company’s investment of $190 million in OMOG was divested in July 2023 as further discussed in Note 4—Ac q uisitions and Divestitures.

Currently, the Company receives distributions from Wink to Webster and prior to their divestitures, received distributions from Gray Oak and OMOG, which are classified either within the operating or investing sections of the consolidated statements of cash flows by determining the nature of each distribution. The following table presents total distributions received from the Company’s equity method investments for the periods indicated:


	Year Ended December 31,
	2023		2022		2021
	(In millions)

Gray Oak Pipeline, LLC	$	—	$	28	$	26
Wink to Webster Pipeline LLC	13		5		—
OMOG JV LLC	23		19		18




Total	$	36	$	52	$	44

The following summarizes the income (loss) of equity method investees for the periods presented:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
EPIC Crude Holdings, LP	$	(8)	$	(7)	$	(16)
Gray Oak Pipeline, LLC	3		22		16
Wink to Webster Pipeline LLC	9		4		(3)
OMOG JV LLC	17		14		12

WTG joint venture	26		44		6

Deep Blue Midland Basin LLC	2		—		—
Other	(1)		—		—
Total	$	48	$	77	$	15

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. If such a loss has occurred, the Company recognizes an impairment provision. No significant impairments were recorded for the Company’s equity method investments for the years ended December 31, 2023, 2022 or 2021. If economic challenges occur in future periods, it could result in circumstances requiring the Company to record potentially material impairment charges on its equity method investments.

In addition to the equity method investments noted above, at December 31, 2023, the Company also has an insignificant investment in the Class A common stock of Verde Clean Fuels, Inc. The Company elected the fair value option for measuring the fair value of this equity investment as discussed further in Note 13— Fair Value Measurements.

Related Party Transactions- Deep Blue

In addition to the equity method investee activity reported above, the Company had other significant related party transactions with Deep Blue which at December 31, 2023, include (i) contingent consideration and other post-close adjustments receivable from Deep Blue, (ii) accrued capital expenditures and other accrued payables related to a commitment to fund certain capital expenditures on projects that were in process at the time of the Deep Blue transaction, and (iii) lease operating expenses and capitalized expenses related to fees paid to Deep Blue under a 15-year dedication for its produced water and supply water within a 12-county area of mutual interest in the Midland Basin.

The following table presents the significant related party balances included in the consolidated balance sheet at December 31, 2023:


	December 31, 2023

	(In millions)
Current assets - Accounts receivable	$	61
Current liabilities - Accrued capital expenditures	$	(21)
Current liabilities - Other accrued liabilities	$	(18)

The following table presents the significant related party transactions included in the consolidated statement of operations for the year ended December 31, 2023:


	Year Ended December 31, 2023

	(In millions)
Lease operating expenses	$	33


Net income (loss)	$	(33)

DEBT - Second Amended and Restated Credit Facility (Details)		12 Months Ended
	Jun. 02, 2022 extension	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 6,641,000,000	$ 6,248,000,000
Credit agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity		1,600,000,000
Potential maximum borrowing capacity		2,600,000,000
Remaining borrowing capacity		$ 1,600,000,000
Weighted average interest rate		6.31%	3.91%	1.67%
Number of extensions \| extension	1
Debt instrument, term	1 year
Credit agreement \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 0
Credit agreement \| Minimum
Line of Credit Facility [Line Items]
Commitment fee percentage based on unused portion of borrowing base	0.125%
Credit agreement \| Maximum
Line of Credit Facility [Line Items]
Commitment fee percentage based on unused portion of borrowing base	0.325%
Debt covenant, total net debt to capitalization ratio		65.00%
Credit agreement \| SOFR
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.10%
Credit agreement \| SOFR \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.125%
Credit agreement \| SOFR \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%
Credit agreement \| SOFR \| One Month
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Credit agreement \| Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Credit agreement \| Base Rate \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.125%
Credit agreement \| Base Rate \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

12 Months Ended

Dec. 31, 2023

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (UNAUDITED)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:


	December 31,
	2023		2022
	(In millions)
Oil and natural gas properties:
Proved properties	$	33,771	$	28,767
Unproved properties	8,659		8,355
Total oil and natural gas properties	42,430		37,122
Accumulated depletion	(8,333)		(6,671)
Accumulated impairment	(7,954)		(7,954)
Net oil and natural gas properties capitalized	$	26,143	$	22,497

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,
	2023		2022		2021
	(In millions)
Acquisition costs:
Proved properties	$	1,314	$	778	$	2,805
Unproved properties	1,701		1,536		1,829
Development costs	1,962		566		516
Exploration costs	768		1,698		1,223

Total	$	5,745	$	4,578	$	6,373

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. 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,
	2023		2022		2021
	(In millions)
Oil, natural gas and natural gas liquid sales	$	8,228	$	9,566	$	6,747



Production costs	(1,684)		(1,521)		(1,202)
Depreciation, depletion, amortization and accretion	(1,684)		(1,264)		(1,211)

Income tax benefit (expense)	(1,000)		(1,437)		(918)
Results of operations	$	3,860	$	5,344	$	3,416

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by the Company’s internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2023 and 2022 and prepared by Ryder Scott as of December 31, 2021. 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 SEC Prices for the periods ending December 31, 2023, 2022 and 2021, respectively. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent the net revenue interest in the Company’s properties, all of which are located within the continental United States. Although the Company believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

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 following table presents changes in the Company’s estimated proved reserves (including those attributable to Viper). As of December 31, 2023, none of the Company’s total proved reserves were classified as proved developed non-producing.


	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBOE)(1)
Proved Developed and Undeveloped Reserves:
As of December 31, 2020	759,401	1,607,064	289,196	1,316,441
Extensions and discoveries	271,222	720,125	127,479	518,722
Revisions of previous estimates	(160,570)	195,302	(6,685)	(134,705)
Purchase of reserves in place	176,261	302,770	58,587	285,310
Divestitures	(36,503)	(70,048)	(11,597)	(59,775)
Production	(81,522)	(169,406)	(27,246)	(137,002)
As of December 31, 2021	928,289	2,585,807	429,734	1,788,991
Extensions and discoveries	201,326	386,987	68,671	334,495
Revisions of previous estimates	(10,483)	2,827	3,228	(6,784)
Purchase of reserves in place	38,683	82,287	15,645	68,043
Divestitures	(6,691)	(12,671)	(2,079)	(10,882)
Production	(81,616)	(176,376)	(29,880)	(140,892)
As of December 31, 2022	1,069,508	2,868,861	485,319	2,032,971
Extensions and discoveries	206,562	424,881	78,498	355,874
Revisions of previous estimates	(56,482)	(47,697)	9,962	(54,470)
Purchase of reserves in place	41,790	79,507	15,440	70,481
Divestitures	(21,258)	(130,013)	(20,755)	(63,682)
Production	(96,176)	(198,117)	(34,217)	(163,413)
As of December 31, 2023	1,143,944	2,997,422	534,247	2,177,761

Proved Developed Reserves:
December 31, 2020	443,464	1,085,035	192,495	816,798
December 31, 2021	620,474	1,770,688	285,513	1,201,102
December 31, 2022	699,513	2,122,782	350,243	1,403,553
December 31, 2023	744,103	2,203,563	385,167	1,496,530

Proved Undeveloped Reserves:
December 31, 2020	315,937	522,029	96,701	499,643
December 31, 2021	307,815	815,119	144,221	587,889
December 31, 2022	369,995	746,079	135,076	629,418
December 31, 2023	399,841	793,859	149,080	681,231

(1) Includes total proved reserves of 78,870 MBOE, 65,516 MBOE, 58,828 MBOE and 41,745 MBOE as of December 31, 2023, 2022, 2021 and 2020, respectively, attributable to a non-controlling interest in Viper.

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, 2023, the Company’s extensions and discoveries of 355,874 MBOE resulted primarily from the drilling of 954 new wells in which the Company has an interest, including 826 wells in which the Company owns only a mineral interest through Viper, and from 344 new proved undeveloped locations added. Viper royalty interests accounted for 7% of the extension volumes. The Company’s downward revisions of previous estimates of 54,470 MBOE were primarily attributable to negative revisions of (i) 62,370 MBOE associated with lower commodity prices and (ii) 32,249 MBOE due to PUD downgrades related to changes in the corporate development plan. These were partially offset by positive revisions of 40,149 MBOE due to improved performance. Purchases of 70,481 MBOE consisted of 54,470 MBOE attributable largely to the Lario Acquisition and 16,011 MBOE of Viper royalty purchases. Divestitures of 63,682 MBOE related primarily to non-core Midland Basin assets.

During the year ended December 31, 2022, the Company’s extensions and discoveries of 334,495 MBOE resulted primarily from the drilling of 654 new wells in which the Company has a working interest, including 576 wells in which we own only a mineral interest through Viper, and from 311 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s downward revisions of previous estimates of 6,784 MBOE were the result of negative revisions of 98,902 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the FireBird Acquisition, partially offset with positive revisions of 92,118 MBOE associated with higher commodity prices. Purchases of 68,043 MBOE consisted of 67,037 MBOE attributable largely to the FireBird Acquisition and 1,005 MBOE of Viper royalty purchases. Divestitures of 10,882 MBOE related primarily to non-core Delaware Basin assets and the Eagle Ford Basin Divestiture.

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 in which the Company has a working interest, 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.

Proved Undeveloped Reserves (PUDs)

At December 31, 2023, the Company’s estimated PUD reserves were approximately 681,231 MBOE, a 51,813 MBOE increase over the reserve estimate at December 31, 2022 of 629,418 MBOE. The following table includes the changes in PUD reserves for 2023 (MBOE):


Beginning proved undeveloped reserves at December 31, 2022			629,418
Undeveloped reserves transferred to developed			(187,097)
Revisions			(34,110)
Purchases			4,206
Divestitures			(7,461)
Extensions and discoveries			276,275
Ending proved undeveloped reserves at December 31, 2023			681,231

The increase in proved undeveloped reserves was primarily attributable to extensions of 266,178 MBOE from 344 gross (295 net) wells in which the Company has a working interest and 10,097 MBOE from 179 gross wells in which Viper owns royalty interests. Of the 344 gross working interest wells, 321 were in the Midland Basin and 23 were in the Delaware Basin. Transfers of 187,097 MBOE from undeveloped to developed reserves were the result of drilling or participating in 204 gross (184 net) horizontal wells in which the Company has a working interest and 170 gross wells in which the Company also has a royalty interest or mineral interest through Viper. Downward revisions of 34,110 MBOE were primarily the result of negative revisions of 25,893 MBOE due to downgrades related to changes in the corporate development plan, and negative revisions of 8,217 MBOE attributable to lower commodity prices. Purchases of 4,206 MBOE consisted of 3,288 MBOE primarily from insignificant trades and acquisitions and 918 MBOE from the GRP Acquisition and other insignificant royalty interest purchases.

During 2023, approximately $2.0 billion 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. Estimated future development costs relating to the development of PUDs are projected to be approximately $1.6 billion in 2024, $1.4 billion in 2025, $930 million in 2026 and $676 million in 2027. Since our formation in 2011, our average drilling costs and drilling times have been reduced, and we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.

With our current development plan, we expect to continue our strong PUD conversion ratio in 2024 by converting an estimated 38% of our PUDs to a proved developed category and developing approximately 83% of the consolidated 2023 year-end PUD reserves by the end of 2026. As of December 31, 2023, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

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, 2023, 2022 and 2021:


	December 31,
	2023		2022		2021
	(In millions)
Future cash inflows	$	106,418	$	137,051	$	77,085
Future development costs(1)	(6,400)		(6,176)		(4,243)
Future production costs	(25,656)		(25,295)		(19,123)
Future production taxes	(7,434)		(9,927)		(5,572)
Future income tax expenses	(11,067)		(17,563)		(7,237)
Future net cash flows	55,861		78,090		40,910
10% discount to reflect timing of cash flows	(28,803)		(42,391)		(22,193)
Standardized measure of discounted future net cash flows(2)	$	27,058	$	35,699	$	18,717

(1) Includes approximately $685 million, $756 million, and $339 million of undiscounted future asset retirement costs for the years ended December 31, 2023, 2022 and 2021, respectively, based on estimates made at the end of each of the respective years,

(2) Includes $3.2 billion, $3.5 billion and $2.1 billion, for the years ended December 31, 2023, 2022 and 2021, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 44%, 44% and 46% non-controlling interest at December 31, 2023 2022 and 2021, respectively.

The table below presents the SEC Prices as adjusted for differentials and contractual arrangements utilized in the computation of future cash inflows:


	December 31,
	2023		2022		2021


Oil (per Bbl)	$	77.62	$	95.26	$	64.78
Natural gas (per Mcf)	$	1.53	$	5.59	$	2.61
Natural gas liquids (per Bbl)	$	24.40	$	39.40	$	23.71

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,
	2023		2022		2021
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	35,699	$	18,717	$	6,758
Sales of oil and natural gas, net of production costs	(6,544)		(8,045)		(5,757)
Acquisitions of reserves	1,854		1,473		1,914
Divestitures of reserves	(938)		(119)		(275)
Extensions and discoveries, net of future development costs	5,771		7,674		6,298
Previously estimated development costs incurred during the period	1,180		823		548
Net changes in prices and production costs	(17,276)		17,785		10,748
Changes in estimated future development costs	518		(317)		(19)
Revisions of previous quantity estimates	(1,268)		102		719
Accretion of discount	4,533		2,183		703
Net change in income taxes	2,506		(4,904)		(2,841)
Net changes in timing of production and other	1,023		327		(79)
Standardized measure of discounted future net cash flows at the end of the period	$	27,058	$	35,699	$	18,717

ACQUISITIONS AND DIVESTITURES - Schedule of Purchase Price Allocation (Details) - USD ($) $ in Millions	Jan. 31, 2023	Nov. 30, 2022	Feb. 26, 2021
Lario Acquisition
Asset Acquisition [Line Items]
Total consideration	$ 1,447
Fair value of liabilities assumed:
Other long-term liabilities	37
Fair value of assets acquired:
Oil and natural gas properties	1,460
Inventories	2
Other property, equipment and land	22
Amount attributable to assets acquired	1,484
Net assets acquired and liabilities assumed	$ 1,447
Firebird Acquisition
Asset Acquisition [Line Items]
Total consideration		$ 1,663
Fair value of liabilities assumed:
Other long-term liabilities		10
Fair value of assets acquired:
Oil and natural gas properties		1,598
Inventories		3
Other property, equipment and land		72
Amount attributable to assets acquired		1,673
Net assets acquired and liabilities assumed		$ 1,663
Guidon Operating LLC
Asset Acquisition [Line Items]
Total consideration			$ 1,115
Fair value of liabilities assumed:
Asset retirement obligations			9
Fair value of assets acquired:
Oil and natural gas properties			1,110
Midstream assets			14
Amount attributable to assets acquired			1,124
Net assets acquired and liabilities assumed			$ 1,115

COMMITMENTS AND CONTINGENCIES - Delivery Commitments (Details) bbl / d in Thousands	Dec. 31, 2023 bbl / d
Commitments and Contingencies Disclosure [Abstract]
2024	175
2025	175
2026	150
2027	150
2028	50
Thereafter	50
Total	750

EQUITY-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Schedule of Stock-based Compensation Plans and Related Costs

The following table presents the financial statement impacts of equity compensation plans and related costs on the Company’s financial statements:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
General and administrative expenses	$	54	$	55	$	51
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	26	$	21	$	20

Schedule of Restricted Stock Units

The following table presents the Company’s restricted stock unit activity during the year ended December 31, 2023 under the Equity Plan:


	Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2022	918,902	$	95.74
Granted	464,367	$	145.45
Vested	(558,077)	$	85.94
Forfeited	(73,996)	$	108.00
Unvested at December 31, 2023	751,196	$	132.29

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 periods presented:


	March 2023			July 2023			2022			2021
Grant-date fair value	$	259.52		$	222.09		$	237.13		$	131.06
Risk-free rate	4.64		%	4.70		%	1.44		%	15.00		%
Company volatility	46.90		%	47.20		%	72.10		%	69.60		%

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, 2023:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2022	347,881	$	168.48
Granted	361,268	$	258.98
Vested	(388,436)	$	134.64
Forfeited	(42,657)	$	144.48
Unvested at December 31, 2023(1)	278,056	$	234.80

(1)A maximum of 645,703 units could be awarded based upon the Company’s final TSR ranking.

INCOME TAXES - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns
Balance at beginning of year	$ 7	$ 7
Decrease resulting from expiration of statute	(7)	0
Balance at end of year	0	7
Less: Effects of temporary items	0	(4)
Total that, if recognized, would impact the effective income tax rate as of the end of the year	$ 0	$ 3

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Narrative (Details) MBoe in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) MBoe well reserve	Dec. 31, 2022 USD ($) MBoe well	Dec. 31, 2021 USD ($) MBoe well	Dec. 31, 2020 MBoe
Oil and Gas, Delivery Commitment [Line Items]
Classified as proved developed non-producing reserves \| reserve	0
Extensions and discoveries	355,874	334,495	518,722
Oil and gas development well drilled net productive \| well	954	654	470
Proved undeveloped reserves number of wells added \| well	344	311	439
Percentage of extension volumes attributable to subsidiary	7.00%	8.00%	6.00%
Revisions of previous estimates	(54,470)	(6,784)	(134,705)
Estimates increase due to higher commodity prices and improved well performance	62,370	92,118	133,855
Change in corporate plan	32,249	98,902	268,560
Performance revisions	40,149
Purchase of reserves in place	70,481	68,043	285,310
Increase due to acquisitions	54,470	67,037	276,207
Royalty purchases	16,011	1,005	9,102
Divestitures	63,682	10,882	59,775
Increase due to purchase of reserves			285,309
Divestitures of reserves			59,775
Proved undeveloped reserves (energy)	681,231	629,418	587,889	499,643
Proved undeveloped reserves, increase (energy)	51,813
Extensions and discoveries, working interest (in MBOE)	266,178
Number of horizontal wells developed, working interest gross \| well	344
Number of horizontal wells developed, working interest \| well	295
Proved undeveloped reserves extensions and discoveries mineral interest	10,097
Number of horizontal wells developed, mineral interest \| well	179
Undeveloped reserves transferred to developed	187,097
Number of horizontal wells developed working interest gross \| well	204
Number of horizontal wells developed working interest net \| well	184
Number of horizontal wells developed mineral interest gross \| well	170
Revisions	34,110
Revisions from PUD reclassifications due to lower benchmark commodity prices	25,893
Revisions from PUD reclassifications due to refinement	8,217
Capital expenditures towards development of proved undeveloped reserves \| $	$ 1,962	$ 566	$ 516
Future development costs, year one \| $	1,600
Future development costs, year two \| $	1,400
Future development costs, year three \| $	930
Future development costs, year four \| $	$ 676
Expected future conversion of PUDS to proved developed category	38.00%
Expected future development of PUD reserves	83.00%
Proved undeveloped reserves, planned development period	5 years
Purchases	4,206
Lario Acquisition and Viper Royalty Interest
Oil and Gas, Delivery Commitment [Line Items]
Purchases	4,206
Lario Acquisition
Oil and Gas, Delivery Commitment [Line Items]
Increase due to purchase of reserves	3,288
Viper Royalty Interest
Oil and Gas, Delivery Commitment [Line Items]
Increase due to purchase of reserves	918
Midland Basin
Oil and Gas, Delivery Commitment [Line Items]
Number of horizontal wells developed working interest \| well	321
Delaware Basin
Oil and Gas, Delivery Commitment [Line Items]
Number of horizontal wells developed working interest \| well	23
Viper
Oil and Gas, Delivery Commitment [Line Items]
Oil and gas development well drilled net productive \| well	826	576	345

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2023

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,
	2023		2022
	(In millions)
Oil and natural gas properties:
Proved properties	$	33,771	$	28,767
Unproved properties	8,659		8,355
Total oil and natural gas properties	42,430		37,122
Accumulated depletion	(8,333)		(6,671)
Accumulated impairment	(7,954)		(7,954)
Net oil and natural gas properties capitalized	$	26,143	$	22,497

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,
	2023		2022		2021
	(In millions)
Acquisition costs:
Proved properties	$	1,314	$	778	$	2,805
Unproved properties	1,701		1,536		1,829
Development costs	1,962		566		516
Exploration costs	768		1,698		1,223

Total	$	5,745	$	4,578	$	6,373

Schedule of Results of Operations From Oil and Natural Gas Producing Activities


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Oil, natural gas and natural gas liquid sales	$	8,228	$	9,566	$	6,747



Production costs	(1,684)		(1,521)		(1,202)
Depreciation, depletion, amortization and accretion	(1,684)		(1,264)		(1,211)

Income tax benefit (expense)	(1,000)		(1,437)		(918)
Results of operations	$	3,860	$	5,344	$	3,416

Schedule of Changes in Estimated Proved Reserves


	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBOE)(1)
Proved Developed and Undeveloped Reserves:
As of December 31, 2020	759,401	1,607,064	289,196	1,316,441
Extensions and discoveries	271,222	720,125	127,479	518,722
Revisions of previous estimates	(160,570)	195,302	(6,685)	(134,705)
Purchase of reserves in place	176,261	302,770	58,587	285,310
Divestitures	(36,503)	(70,048)	(11,597)	(59,775)
Production	(81,522)	(169,406)	(27,246)	(137,002)
As of December 31, 2021	928,289	2,585,807	429,734	1,788,991
Extensions and discoveries	201,326	386,987	68,671	334,495
Revisions of previous estimates	(10,483)	2,827	3,228	(6,784)
Purchase of reserves in place	38,683	82,287	15,645	68,043
Divestitures	(6,691)	(12,671)	(2,079)	(10,882)
Production	(81,616)	(176,376)	(29,880)	(140,892)
As of December 31, 2022	1,069,508	2,868,861	485,319	2,032,971
Extensions and discoveries	206,562	424,881	78,498	355,874
Revisions of previous estimates	(56,482)	(47,697)	9,962	(54,470)
Purchase of reserves in place	41,790	79,507	15,440	70,481
Divestitures	(21,258)	(130,013)	(20,755)	(63,682)
Production	(96,176)	(198,117)	(34,217)	(163,413)
As of December 31, 2023	1,143,944	2,997,422	534,247	2,177,761

Proved Developed Reserves:
December 31, 2020	443,464	1,085,035	192,495	816,798
December 31, 2021	620,474	1,770,688	285,513	1,201,102
December 31, 2022	699,513	2,122,782	350,243	1,403,553
December 31, 2023	744,103	2,203,563	385,167	1,496,530

Proved Undeveloped Reserves:
December 31, 2020	315,937	522,029	96,701	499,643
December 31, 2021	307,815	815,119	144,221	587,889
December 31, 2022	369,995	746,079	135,076	629,418
December 31, 2023	399,841	793,859	149,080	681,231

The following table includes the changes in PUD reserves for 2023 (MBOE):


Beginning proved undeveloped reserves at December 31, 2022			629,418
Undeveloped reserves transferred to developed			(187,097)
Revisions			(34,110)
Purchases			4,206
Divestitures			(7,461)
Extensions and discoveries			276,275
Ending proved undeveloped reserves at December 31, 2023			681,231

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, 2023, 2022 and 2021:


	December 31,
	2023		2022		2021
	(In millions)
Future cash inflows	$	106,418	$	137,051	$	77,085
Future development costs(1)	(6,400)		(6,176)		(4,243)
Future production costs	(25,656)		(25,295)		(19,123)
Future production taxes	(7,434)		(9,927)		(5,572)
Future income tax expenses	(11,067)		(17,563)		(7,237)
Future net cash flows	55,861		78,090		40,910
10% discount to reflect timing of cash flows	(28,803)		(42,391)		(22,193)
Standardized measure of discounted future net cash flows(2)	$	27,058	$	35,699	$	18,717

Schedule of Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids

The table below presents the SEC Prices as adjusted for differentials and contractual arrangements utilized in the computation of future cash inflows:


	December 31,
	2023		2022		2021


Oil (per Bbl)	$	77.62	$	95.26	$	64.78
Natural gas (per Mcf)	$	1.53	$	5.59	$	2.61
Natural gas liquids (per Bbl)	$	24.40	$	39.40	$	23.71

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,
	2023		2022		2021
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	35,699	$	18,717	$	6,758
Sales of oil and natural gas, net of production costs	(6,544)		(8,045)		(5,757)
Acquisitions of reserves	1,854		1,473		1,914
Divestitures of reserves	(938)		(119)		(275)
Extensions and discoveries, net of future development costs	5,771		7,674		6,298
Previously estimated development costs incurred during the period	1,180		823		548
Net changes in prices and production costs	(17,276)		17,785		10,748
Changes in estimated future development costs	518		(317)		(19)
Revisions of previous quantity estimates	(1,268)		102		719
Accretion of discount	4,533		2,183		703
Net change in income taxes	2,506		(4,904)		(2,841)
Net changes in timing of production and other	1,023		327		(79)
Standardized measure of discounted future net cash flows at the end of the period	$	27,058	$	35,699	$	18,717

- Definition

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.

+ References + Details

- Definition

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.

+ References + Details

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023, 2022 and 2021 are as follows:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Current income tax provision (benefit):
Federal	$	505	$	421	$	10
State	29		33		15
Total current income tax provision (benefit)	534		454		25
Deferred income tax provision (benefit):
Federal	370		706		594
State	8		14		12
Total deferred income tax provision (benefit)	378		720		606
Total provision for (benefit from) income taxes	$	912	$	1,174	$	631

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,
	2023		2022		2021
	(In millions)
Income tax expense (benefit) at the federal statutory rate (21%)	$	892	$	1,205	$	610


State income tax expense, net of federal tax effect	31		42		23
Non-deductible compensation	8		10		10
Change in valuation allowance	(7)		(71)		(12)
Other, net	(12)		(12)		—
Provision for (benefit from) income taxes	$	912	$	1,174	$	631

Schedule of Deferred Tax Assets and Liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2023 and 2022 are as follows:


	December 31,
	2023		2022
	(In millions)












Deferred tax assets:
Net operating loss and other carryforwards	$	236	$	406
Derivative instruments	22		—
Stock based compensation	7		5

Viper's investment in Viper LLC	170		148
Rattler's investment in Rattler LLC	—		1
Other	21		16
Deferred tax assets	456		576
Valuation allowance	(233)		(223)
Deferred tax assets, net of valuation allowance	223		353
Deferred tax liabilities:
Oil and natural gas properties and equipment	2,463		2,109
Midstream investments	162		235
Derivative instruments	—		12

Other	2		2
Total deferred tax liabilities	2,627		2,358
Net deferred tax liabilities	$	2,404	$	2,005

Schedule of Unrecognized Tax Benefits

The following table sets forth changes in the Company’s unrecognized tax benefits:


	December 31,
	2023		2022
	(In millions)
Balance at beginning of year	$	7	$	7


Decrease resulting from expiration of statute	(7)		—

Balance at end of year	—		7
Less: Effects of temporary items	—		(4)
Total that, if recognized, would impact the effective income tax rate as of the end of the year	$	—	$	3

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Oil and natural gas properties:
Proved properties	$ 33,771	$ 28,767
Unproved properties	8,659	8,355
Total oil and natural gas properties	42,430	37,122
Accumulated depletion	(8,333)	(6,671)
Accumulated impairment	(7,954)	(7,954)
Oil and natural gas properties, net	$ 26,143	$ 22,497

DEBT - Retirement of Notes (Details) - USD ($)	3 Months Ended			12 Months Ended
DEBT - Retirement of Notes (Details) - USD ($)	Jun. 30, 2023	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	May 01, 2023	Sep. 30, 2022
Debt Instrument [Line Items]
Cash consideration of debt				$ 134,000,000	$ 2,410,000,000	$ 3,193,000,000
Loss on extinguishment of debt				$ 4,000,000	$ 99,000,000	$ 75,000,000
Senior Notes
Debt Instrument [Line Items]
Cash consideration of debt	$ 124,000,000	$ 322,000,000
3.250% Senior Notes due 2026 \| Senior Notes
Debt Instrument [Line Items]
Repurchased face amount	$ 30,000,000	20,000,000
Stated interest rate	3.25%			3.25%
3.500% Senior Notes due 2029 \| Senior Notes
Debt Instrument [Line Items]
Repurchased face amount	$ 100,000,000	179,000,000
Stated interest rate	3.50%			3.50%
5.250% Senior Notes due 2023 \| Senior Notes
Debt Instrument [Line Items]
Repurchased face amount							$ 10,000,000
Stated interest rate				5.25%
5.375% Senior Notes Due 2022
Debt Instrument [Line Items]
Repurchased face amount								$ 25,000,000
Stated interest rate								5.375%
7.320% Medium Term Series A due 2022
Debt Instrument [Line Items]
Repurchased face amount								$ 20,000,000
Stated interest rate								7.32%
5.625% Senior Notes Due 2025
Debt Instrument [Line Items]
Repurchased face amount								$ 500,000,000
Stated interest rate								5.625%
Repurchase amount								$ 522,000,000
7.125% Medium-term Notes, Series B, due 2028 \| Medium-term Notes
Debt Instrument [Line Items]
Repurchased face amount		$ 27,000,000
Stated interest rate		7.125%		7.125%
3.125% Senior Notes due 2031 \| Senior Notes
Debt Instrument [Line Items]
Repurchased face amount		$ 111,000,000
Stated interest rate		3.125%		3.125%
Viper 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Cash consideration of debt		$ 49,000,000
Repurchase amount		$ 50,000,000
Viper 5.375% Senior Notes due 2027 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate		5.375%		5.375%
4.750% Senior Notes due 2025 and 2.875% Senior Notes due 2024 \| Senior Notes
Debt Instrument [Line Items]
Cash consideration of debt			$ 1,600,000,000
Redemption premium fees			47,000,000
Loss on extinguishment of debt			$ 54,000,000
4.750% Senior Notes due 2025 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate			4.75%
Repurchase amount			$ 500,000,000
2.875% Senior Notes due 2024 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate			2.875%
Repurchase amount			$ 1,000,000,000

STOCKHOLDERS’ EQUITY AND EARNINGS (LOSS) PER SHARE - Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Net income (loss) attributable to common stock	$ 3,143	$ 4,386	$ 2,182
Less: distributed and undistributed earnings allocated to participating securities	22	42	20
Net income (loss) attributable to common stockholders	$ 3,121	$ 4,344	$ 2,162
Weighted average common shares outstanding:
Basic weighted average common shares outstanding (in shares)	179,999	176,539	176,643
Effect of dilutive securities:
Weighted-average potential common shares issuable (in shares)	0	0	0
Diluted weighted average common shares outstanding (in shares)	179,999	176,539	176,643
Basic net income (loss) attributable to common stock (in USD per share)	$ 17.34	$ 24.61	$ 12.24
Diluted net income (loss) attributable to common stock (in USD per share)	$ 17.34	$ 24.61	$ 12.24

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Oil and Natural Gas Reserves (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2023 MBoe MBbls MMcf	Dec. 31, 2022 MBoe MBbls MMcf	Dec. 31, 2021 MBoe MBbls MMcf	Dec. 31, 2020 MBoe MBbls MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Total, beginning balance \| MBoe	2,032,971	1,788,991	1,316,441
Extensions and discoveries \| MBoe	355,874	334,495	518,722
Revisions of previous estimates \| MBoe	(54,470)	(6,784)	(134,705)
Purchase of reserves in place \| MBoe	70,481	68,043	285,310
Divestitures \| MBoe	(63,682)	(10,882)	(59,775)
Production \| MBoe	(163,413)	(140,892)	(137,002)
Total, ending balance \| MBoe	2,177,761	2,032,971	1,788,991
Proved developed reserves (energy) \| MBoe	1,496,530	1,403,553	1,201,102	816,798
Proved undeveloped reserves (energy) \| MBoe	681,231	629,418	587,889	499,643
Viper
Proved Developed and Undeveloped Reserves [Roll Forward]
Total, beginning balance \| MBoe	65,516	58,828	41,745
Total, ending balance \| MBoe	78,870	65,516	58,828
OIL
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	1,069,508	928,289	759,401
Extensions and discoveries	206,562	201,326	271,222
Revisions of previous estimates	(56,482)	(10,483)	(160,570)
Purchase of reserves in place	41,790	38,683	176,261
Divestitures	(21,258)	(6,691)	(36,503)
Production	(96,176)	(81,616)	(81,522)
End of the period	1,143,944	1,069,508	928,289
Proved developed reserves (volume)	744,103	699,513	620,474	443,464
Proved undeveloped reserve (volume)	399,841	369,995	307,815	315,937
NATURAL GAS LIQUIDS
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	485,319	429,734	289,196
Extensions and discoveries	78,498	68,671	127,479
Revisions of previous estimates	9,962	3,228	(6,685)
Purchase of reserves in place	15,440	15,645	58,587
Divestitures	(20,755)	(2,079)	(11,597)
Production	(34,217)	(29,880)	(27,246)
End of the period	534,247	485,319	429,734
Proved developed reserves (volume)	385,167	350,243	285,513	192,495
Proved undeveloped reserve (volume)	149,080	135,076	144,221	96,701
NATURAL GAS
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period \| MMcf	2,868,861	2,585,807	1,607,064
Extensions and discoveries \| MMcf	424,881	386,987	720,125
Revisions of previous estimates \| MMcf	(47,697)	2,827	195,302
Purchase of reserves in place \| MMcf	79,507	82,287	302,770
Divestitures \| MMcf	(130,013)	(12,671)	(70,048)
Production \| MMcf	(198,117)	(176,376)	(169,406)
End of the period \| MMcf	2,997,422	2,868,861	2,585,807
Proved developed reserves (volume) \| MMcf	2,203,563	2,122,782	1,770,688	1,085,035
Proved undeveloped reserve (volume) \| MMcf	793,859	746,079	815,119	522,029

EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS - Investments (Details) - USD ($) $ in Millions	1 Months Ended
	Jul. 31, 2023	Dec. 31, 2023	Sep. 01, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 529		$ 566
Aggregate Investments
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 529		681
EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Ownership Interest		10.00%
Equity method investments		$ 93		101
Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		0.00%
Equity method investments		$ 0		115
Equity method investment, classified as held for sale				115
Wink to Webster Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		4.00%
Equity method investments		$ 92		87
OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		0.00%
Equity method investments		$ 0		191
Equity method investment, amount sold	$ 190
BANGL LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		10.00%
Equity method investments		$ 29		28
WTG joint venture
Schedule of Equity Method Investments [Line Items]
Ownership Interest		25.00%
Equity method investments		$ 182		156
Deep Blue Midland Basin LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		30.00%	30.00%
Equity method investments		$ 128	$ 126	0
Other
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 5		$ 3

PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

Property and equipment includes the following:


	December 31,
	2023		2022
	(In millions)
Oil and natural gas properties:
Subject to depletion	$	33,771	$	28,767
Not subject to depletion	8,659		8,355
Gross oil and natural gas properties	42,430		37,122
Accumulated depletion	(8,333)		(6,671)
Accumulated impairment	(7,954)		(7,954)
Oil and natural gas properties, net	26,143		22,497
Other property, equipment and land	673		1,481
Accumulated depreciation, amortization, accretion and impairment	(142)		(219)
Total property and equipment, net	$	26,674	$	23,759

Balance of costs not subject to depletion:
Incurred in 2023	$	1,470
Incurred in 2022	827
Incurred in 2021	1,136


Prior	5,226
Total not subject to depletion	$	8,659

Capitalized internal costs were approximately $66 million, $58 million and $60 million for the years ended December 31, 2023, 2022 and 2021, 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. Although the evaluation process has not been completed on our unevaluated properties, the Company currently estimates these costs will be added to the amortization base 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 years ended December 31, 2023, 2022 and 2021.

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.

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 was not 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.

At December 31, 2023, there were $77 million in exploration and development costs and $337 million in capitalized interest that are not subject to depletion. At December 31, 2022, there were $126 million in exploration and development costs and $206 million in capitalized interest costs that were not subject to depletion.

DERIVATIVES - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net:	$ (259)	$ (586)	$ (848)
Net cash received (paid) on settlements:	(110)	(850)	(1,225)
Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net:	(239)	(528)	(978)
Net cash received (paid) on settlements:	(61)	(849)	(1,305)
Derivative cash paid on hedge		138	16
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net:	(20)	(58)	130
Net cash received (paid) on settlements:	$ (49)	$ (1)	$ 80

EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Units - Narrative (Details) - Performance Shares - Equity Plan - USD ($) $ in Millions	1 Months Ended				12 Months Ended
	Jul. 31, 2023	Mar. 31, 2023	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period		3 years	3 years	3 years	3 years
Granted (in shares)	1,858	126,347	126,905	198,454	361,268
Share based award not recognized					$ 35
Unrecognized compensation cost, expected period of recognition					2 years
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%	250.00%
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%

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2023

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.

See Note 4—Acquisitions and Divestitures for discussion of the fair values of proved oil and natural gas properties assumed in business combinations.

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, interest rate swaps, and investments in the common stock of other entities. 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. The fair values of the Company’s interest rate swaps are determined based on inputs that are readily available in public markets, are determined based on inputs 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 fair value of interest rate swaps is recorded as an asset or liability on the consolidated balance sheets. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates. The Company has an immaterial investment that is reported at fair value using observable, quoted stock prices and is included in “Other assets” on the Company’s consolidated balance sheet at December 31, 2023.


	As of December 31, 2023
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	88	$	—	$	88	$	(71)	$	17

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	8	$	—	$	8	$	(7)	$	1

Non-current assets- Other assets:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	111	$	—	$	111	$	(71)	$	40
Interest rate swaps	$	—	$	46	$	—	$	46	$	—	$	46
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	12	$	—	$	12	$	(7)	$	5
Interest rate swaps	$	—	$	117	$	—	$	117	$	—	$	117


	As of December 31, 2022
	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 assets- Derivative instruments:
Commodity derivative instruments	$	—	$	197	$	—	$	197	$	(65)	$	132

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	62	$	—	$	62	$	(39)	$	23

Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	67	$	—	$	67	$	(65)	$	2
Interest rate swaps	$	—	$	45	$	—	$	45	$	—	$	45
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	39	$	—	$	39	$	(39)	$	—
Interest rate swaps	$	—	$	148	$	—	$	148	$	—	$	148

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, 2023				December 31, 2022
	Carrying				Carrying
	Value		Fair Value		Value		Fair Value
	(In millions)
Debt	$	6,641	$	6,507	$	6,248	$	5,754

The fair values of the Company’s credit agreement and the Viper credit agreement approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair values of the outstanding notes were determined using the quoted market prices at each period end, 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, equity method investments, asset retirement obligations 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 5—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, prepaid expenses, other current assets, payables and other accrued liabilities and funds held in escrow approximate their fair value because of the short-term nature of the instruments.

- Definition

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.

+ References + Details

SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$ (146)	$ (135)	$ (194)
Cash (paid) received for income taxes, net	(352)	(718)	138
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses	618	520	287
Capitalized stock-based compensation	26	21	20
Common stock issued for acquisitions	633	1,220	1,727
Assets contributed in exchange for ownership interest in an equity method investment	126	0	0
Asset retirement obligations acquired	$ 8	$ 19	$ 65

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine 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, employment claims, claims alleging violations of antitrust laws, 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 accrued liabilities 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, 2023:


Year Ending December 31,	Transportation Commitments(1)		Electrical Fracturing Fleet(2)		Sand Supply Agreement(3)		Produced Water Disposal Commitments(4)		Electrical Power Agreements(5)
	(In millions)
2024	$	98	$	50	$	26	$	5	$	72
2025	103		40		22		3		72
2026	109		3		18		4		71
2027	77		—		4		4		70
2028	67		—		—		3		37
Thereafter	314		—		—		21		85
Total	$	768	$	93	$	70	$	40	$	407

(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)In 2022, the Company entered into commitments for three years for the Company’s electric fracturing fleet and related power generating services.

(3)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.

(4)The Company has a minimum volume commitment to purchase produced water disposal services under a 14 year agreement which began in 2021.

(5)The Company has fixed price contracts with various suppliers for the purchase of electrical power through 2032.

At December 31, 2023, the Company’s delivery commitments covered the following gross volumes of oil:


Year Ending December 31,						Oil Volume Commitments (Bbl/d)
2024						175,000
2025						175,000
2026						150,000
2027						150,000
2028						50,000
Thereafter						50,000
Total						750,000

See Note 4—Acquisitions and Divestitures for further details on commitments acquired during the Deep Blue transaction.

Environmental Matters

The United States Department of the Interior, Bureau of Safety and Environmental Enforcement, ordered several oil and gas operators, including a corporate predecessor of Energen Corporation, to perform decommissioning and reclamation activities related to a Louisiana offshore oil and gas production platform and related facilities. In response to the insolvency of the operator of record, the government ordered the former operators and/or alleged former lease record title owners to decommission the platform and related facilities. The Company has agreed to an arrangement with other operators to contribute to a trust to fund the decommissioning costs, however, the Company’s portion of such costs are not expected to be material.

Beginning in 2013 and continuing through the fourth quarter of 2023, several coastal Louisiana parishes and the State of Louisiana have filed 43 lawsuits under Louisiana’s State and Local Coastal Resources Management Act (“SLCRMA”) against numerous oil and gas producers seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone. The Company is a defendant in three of these cases, and Plaintiffs’ claims against the Company relate to the prior operations of entities previously acquired by Energen Corporation. The Company has exercised contractual indemnification rights where applicable. Plaintiffs’ SLCRMA theories are unprecedented, and there remains significant uncertainty about the claims (both as to scope and damages). Although we cannot predict the ultimate outcome of these matters, the Company believes the claims lack merit and intends to continue vigorously defending these lawsuits.

INCOME TAXES - Components of Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income tax provision (benefit):
Federal	$ 505	$ 421	$ 10
State	29	33	15
Total current income tax provision (benefit)	534	454	25
Deferred income tax provision (benefit):
Federal	370	706	594
State	8	14	12
Total deferred income tax provision (benefit)	378	720	606
Provision for (benefit from) income taxes	$ 912	$ 1,174	$ 631

- Definition

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

+ References + Details

DEBT - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
2024	$ 0
2025	0
2026	764
2027	430
2028	336
Thereafter	5,260
Total debt, net	$ 6,790

DEBT - Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
DEBT - Interest Expense (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Interest expense	$ 346	$ 272	$ 277
Other fees and expenses	2	12	11
Less: interest income	2	1	1
Less: capitalized interest	171	124	88
Interest expense, net	$ 175	$ 159	$ 199

- Definition

Amount of the cost of borrowed funds accounted for as interest expense.

+ References + Details

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023:


Year Ending December 31,	Transportation Commitments(1)		Electrical Fracturing Fleet(2)		Sand Supply Agreement(3)		Produced Water Disposal Commitments(4)		Electrical Power Agreements(5)
	(In millions)
2024	$	98	$	50	$	26	$	5	$	72
2025	103		40		22		3		72
2026	109		3		18		4		71
2027	77		—		4		4		70
2028	67		—		—		3		37
Thereafter	314		—		—		21		85
Total	$	768	$	93	$	70	$	40	$	407

(2)In 2022, the Company entered into commitments for three years for the Company’s electric fracturing fleet and related power generating services.

(4)The Company has a minimum volume commitment to purchase produced water disposal services under a 14 year agreement which began in 2021.

(5)The Company has fixed price contracts with various suppliers for the purchase of electrical power through 2032.

Schedule of Delivery Commitment

At December 31, 2023, the Company’s delivery commitments covered the following gross volumes of oil:


Year Ending December 31,						Oil Volume Commitments (Bbl/d)
2024						175,000
2025						175,000
2026						150,000
2027						150,000
2028						50,000
Thereafter						50,000
Total						750,000

REVENUE FROM CONTRACTS WITH CUSTOMERS

12 Months Ended

Dec. 31, 2023

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:


	Year Ended December 31,
	2023		2022		2021
	(In millions)
Oil sales	$	7,279	$	7,660	$	5,396
Natural gas sales	262		858		569
Natural gas liquid sales	687		1,048		782
Total oil, natural gas and natural gas liquid revenues	8,228		9,566		6,747
Sales of purchased oil	111		—		—
Midstream and marketing services	62		69		45
Total revenue from contracts with customers	$	8,401	$	9,635	$	6,792

The following tables present the Company’s revenue from oil, natural gas, and natural gas liquids disaggregated by basin:


	Year Ended December 31, 2023
	Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	5,746	$	1,527	$	6	$	7,279
Natural gas sales	176		85		1		262
Natural gas liquid sales	500		187		—		687
Total	$	6,422	$	1,799	$	7	$	8,228


	Year Ended December 31, 2022
	Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	5,541	$	2,107	$	12	$	7,660
Natural gas sales	563		292		3		858
Natural gas liquid sales	719		327		2		1,048
Total	$	6,823	$	2,726	$	17	$	9,566


	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

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, 2023, four purchasers each accounted for more than 10% of our revenue: Vitol Inc. (“Vitol”) (22%), DK Trading & Supply LLC (18%), Shell Trading (USA) Company (“Shell”) (14%) and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2022, two purchasers each accounted for more than 10% of the Company’s revenue: Vitol (23%) and Shell (20%). For the year ended December 31, 2021, three purchasers each accounted for more than 10% of the Company’s revenue: Vitol (21%); Shell (19%); and Plains Marketing, L.P. (12%). 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.

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-9

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-10

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-15

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-13

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org//606/tableOfContent

+ Details

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance at beginning of period	$ (7)
Balance at end of period	(8)	$ (7)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance at beginning of period	(7)	0
Net actuarial gain (loss) on pension and postretirement benefit plans	(1)	(9)
Income tax benefit (expense)	0	2
Balance at end of period	$ (8)	$ (7)

- Definition

Amount, after tax, of accumulated increase (decrease) in equity from transaction and other event and circumstance from nonowner source.

+ References + Details

ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2023

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,
	2023		2022
	(In millions)
Asset retirement obligations, beginning of period	$	347	$	171
Additional liabilities incurred	4		36
Liabilities acquired	8		19
Liabilities settled and divested	(88)		(26)
Accretion expense	16		14
Revisions in estimated liabilities(1)	(42)		133
Asset retirement obligations, end of period	245		347
Less: current portion(2)	6		11
Asset retirement obligations - long-term	$	239	$	336

(2) The current portion of the asset retirement obligation is included in the caption “Other accrued liabilities” in the Company’s consolidated balance sheets.

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
Total consideration \| $	$ 987

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Average First Day of the Month Price for Oil, Natural Gas & Natural Gas Liquids (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl $ / Mcf	Dec. 31, 2022 $ / bbl $ / Mcf	Dec. 31, 2021 $ / bbl $ / Mcf
OIL
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit)	77.62	95.26	64.78
NATURAL GAS
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit) \| $ / Mcf	1.53	5.59	2.61
NATURAL GAS LIQUIDS
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit)	24.40	39.40	23.71

EQUITY-BASED COMPENSATION - Restricted Stock Units (Details) - Equity Plan - Restricted Stock Units (RSUs)	12 Months Ended
	Dec. 31, 2023 $ / shares shares
Restricted Stock Units
Unvested, beginning balance (in shares) \| shares	918,902
Granted (in shares) \| shares	464,367
Vested (in shares) \| shares	(558,077)
Forfeited (in shares) \| shares	(73,996)
Unvested, ending balance (in shares) \| shares	751,196
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in dollars per share) \| $ / shares	$ 95.74
Granted (in dollars per share) \| $ / shares	145.45
Vested (in dollars per share) \| $ / shares	85.94
Forfeited (in dollars per share) \| $ / shares	108.00
Unvested, ending balance (in dollars per share) \| $ / shares	$ 132.29

DERIVATIVES

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

At December 31, 2023, the Company has commodity derivative contracts and interest rate swaps outstanding. All derivative financial instruments are recorded at fair value.

Commodity Contracts

The Company has entered into multiple crude oil and natural gas 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 has entered into commodity derivative instruments only with counterparties that are also lenders under its credit facility and have been deemed an acceptable credit risk. As such, collateral is not required from either the counterparties or the Company on its outstanding commodity derivative contracts.

As of December 31, 2023, 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 Floor Price	Weighted Average Ceiling Price
OIL
Jan. - Jun.	2024	Costless Collar	6,000	WTI Cushing	$—		$65.00	$95.55
Jan. - Dec.	2024	Basis Swap(1)	10,000	Argus WTI Midland	$1.19		$—	$—
Jan. - Dec.	2024	Roll Swap	30,000	WTI	$0.81		$—	$—
Jul. - Dec.	2024	Costless Collar	4,000	WTI Cushing	$—		$55.00	$93.66
NATURAL GAS
Jan. - Dec.	2024	Costless Collar	290,000	Henry Hub	$—		$2.83	$7.52
Jan. - Dec.	2024	Basis Swap(1)	380,000	Waha Hub	$(1.18)		$—	$—
Jan. - Dec.	2025	Basis Swap(1)	310,000	Waha Hub	$(0.69)		$—	$—


Settlement Month	Settlement Year	Type of Contract	Bbls Per Day	Index	Strike Price	Deferred Premium
OIL
Jan. - Mar.	2024	Put	124,000	Brent	$55.40	$1.48
Jan. - Mar.	2024	Put	32,000	Argus WTI Houston	$55.00	$1.60
Jan. - Mar.	2024	Put	16,000	WTI Cushing	$58.13	$1.54
Apr. - Jun.	2024	Put	108,000	Brent	$55.46	$1.49
Apr. - Jun.	2024	Put	26,000	Argus WTI Houston	$55.00	$1.56
Apr. - Jun.	2024	Put	14,000	WTI Cushing	$59.29	$1.51
Jul. - Sep.	2024	Put	66,000	Brent	$55.15	$1.53
Jul. - Sep.	2024	Put	18,000	Argus WTI Houston	$55.00	$1.55
Jul. - Sep.	2024	Put	2,000	WTI Cushing	$55.00	$1.53
Oct. - Dec.	2024	Put	34,000	Brent	$55.00	$1.61
Oct. - Dec.	2024	Put	4,000	Argus WTI Houston	$55.00	$1.72
Oct. - Dec.	2024	Put	2,000	WTI Cushing	$55.00	$1.53

Interest Rate Swaps

In the second quarter of 2021, the Company entered into two interest rate swap agreements for notional amounts of $600 million, which were designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) at inception. The Company receives a fixed 3.50% rate of interest on these swaps. Effective on May 28, 2023, the variable rate of interest the Company pays on these swaps was reset from three month LIBOR to three month SOFR plus 2.1865%. The Company previously adopted the optional expedient in ASU 2020-04, “Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting,” as later extended for these contract term modifications, and as a result, did not recognize any impact of the change in reference rate on its financial position, results of operations or liquidity for the year ended December 31, 2023.

In the second quarter of 2022, the Company elected to fully dedesignate these interest rate swaps and hedge accounting was discontinued. The cumulative fair value basis adjustment recorded on the 2029 Notes at the time of

dedesignation totaled $135 million. This basis adjustment is being amortized to interest expense over the remaining term of the 2029 Notes utilizing the effective interest method. See Note 8—Debt for further details. The dedesignated interest rate swaps are considered economic hedges of the Company’s fixed-rate debt. As such, changes in the fair value of the interest rate swaps after the date of dedesignation have been recorded in earnings under the caption “Gain (loss) on derivative instruments, net” in the consolidated statements of operations.

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 13—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,
	2023		2022		2021
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	(239)	$	(528)	$	(978)
Interest rate swaps	(20)		(58)		130
Total	$	(259)	$	(586)	$	(848)

Net cash received (paid) on settlements:
Commodity contracts(1)	$	(61)	$	(849)	$	(1,305)
Interest rate swaps(2)	(49)		(1)		80
Total	$	(110)	$	(850)	$	(1,225)

(1)The years ended December 31, 2022 and 2021 include cash paid on commodity contracts terminated prior to their contractual maturity of $138 million and $16 million, respectively.

(2)The year ended December 31, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Proved Undeveloped Reserves (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2023 MBoe
Proved Undeveloped Reserves (Energy)
Beginning proved undeveloped reserves at December 31, 2022	629,418
Undeveloped reserves transferred to developed	(187,097)
Revisions	(34,110)
Purchases	4,206
Divestitures	(7,461)
Extensions and discoveries	276,275
Ending proved undeveloped reserves at December 31, 2023	681,231

PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Schedule of Property and Equipment

Property and equipment includes the following:


	December 31,
	2023		2022
	(In millions)
Oil and natural gas properties:
Subject to depletion	$	33,771	$	28,767
Not subject to depletion	8,659		8,355
Gross oil and natural gas properties	42,430		37,122
Accumulated depletion	(8,333)		(6,671)
Accumulated impairment	(7,954)		(7,954)
Oil and natural gas properties, net	26,143		22,497
Other property, equipment and land	673		1,481
Accumulated depreciation, amortization, accretion and impairment	(142)		(219)
Total property and equipment, net	$	26,674	$	23,759

Balance of costs not subject to depletion:
Incurred in 2023	$	1,470
Incurred in 2022	827
Incurred in 2021	1,136


Prior	5,226
Total not subject to depletion	$	8,659