Cover
Cover - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2023 | Feb. 16, 2024 | Jun. 30, 2023 | |
Entity Information [Line Items] | |||
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 | 001-36505 | ||
Entity Registrant Name | Viper Energy, Inc. | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 46-5001985 | ||
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 | Class A Common Stock, $0.000001 Par Value | ||
Trading Symbol | VNOM | ||
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 | $ 1.9 | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of Viper 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 | 0001602065 | ||
Class A Shares | |||
Entity Information [Line Items] | |||
Entity Common Shares Outstanding | 86,144,273 | ||
Class B Shares | |||
Entity Information [Line Items] | |||
Entity Common Shares Outstanding | 90,709,946 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Firm ID | 248 |
Auditor Name | GRANT THORNTON LLP |
Auditor Location | Oklahoma City, Oklahoma |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Current assets: | ||
Cash and cash equivalents | $ 25,869 | $ 18,179 |
Derivative instruments | 358 | 9,328 |
Prepaid expenses and other current assets | 4,467 | 2,468 |
Total current assets | 143,517 | 118,620 |
Property: | ||
Oil and natural gas interests, full cost method of accounting ($1,769,341 and $1,297,221 excluded from depletion at December 31, 2023 and December 31, 2022, respectively) | 4,628,983 | 3,464,819 |
Land | 5,688 | 5,688 |
Accumulated depletion and impairment | (866,352) | (720,234) |
Property, net | 3,768,319 | 2,750,273 |
Derivative instruments | 92 | 442 |
Deferred income taxes (net of allowances) | 56,656 | 49,656 |
Other assets | 5,509 | 1,382 |
Total assets | 3,974,093 | 2,920,373 |
Current liabilities: | ||
Accrued liabilities | 27,021 | 19,600 |
Derivative instruments | 2,961 | 0 |
Income taxes payable | 1,925 | 911 |
Total current liabilities | 33,256 | 21,946 |
Long-term debt, net | 1,083,082 | 576,895 |
Derivative instruments | 201 | 7 |
Total liabilities | 1,116,539 | 598,848 |
Commitments and Contingencies | ||
Stockholders’ equity: | ||
General Partner | 0 | 649 |
Additional paid-in capital | 1,031,078 | 0 |
Retained earnings (accumulated deficit) | (16,786) | 0 |
Total Viper Energy, Inc. stockholders’ equity | 1,014,292 | 690,659 |
Non-controlling interest | 1,843,262 | 1,630,866 |
Total equity | 2,857,554 | 2,321,525 |
Total liabilities and stockholders’ equity | 3,974,093 | 2,920,373 |
Common Units | ||
Stockholders’ equity: | ||
Common units | 0 | 689,178 |
Class B Units | ||
Stockholders’ equity: | ||
Common units | 0 | 832 |
Class A Shares | ||
Stockholders’ equity: | ||
Common Stock | 0 | 0 |
Class B Shares | ||
Stockholders’ equity: | ||
Common Stock | 0 | 0 |
Nonrelated Party | ||
Current assets: | ||
Royalty income receivable | 108,681 | 81,657 |
Current liabilities: | ||
Accounts payable | 19 | 1,129 |
Related Party | ||
Current assets: | ||
Royalty income receivable | 3,329 | 6,260 |
Income tax receivable | 813 | 728 |
Current liabilities: | ||
Accounts payable | $ 1,330 | $ 306 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Not subject to depletion | $ 1,769,341 | $ 1,297,221 |
Common Units | ||
Limited partners' capital account, units outstanding (in units) | 73,229,645 | |
Limited partners' capital account, units issued (in units) | 73,229,645 | |
Class B Units | ||
Limited partners' capital account, units outstanding (in units) | 90,709,946 | |
Limited partners' capital account, units issued (in units) | 90,709,946 | |
Class A Shares | ||
Common stock par value (usd per share) | $ 0.000001 | |
Common stock authorized (in shares) | 1,000,000,000,000 | |
Common stock issued (in shares) | 86,144,273 | |
Common stock outstanding (in shares) | 86,144,273 | |
Class B Shares | ||
Common stock par value (usd per share) | $ 0.000001 | |
Common stock authorized (in shares) | 1,000,000,000,000 | |
Common stock issued (in shares) | 90,709,946 | |
Common stock outstanding (in shares) | 90,709,946 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating income: | |||
Royalty income | $ 717,110 | $ 837,976 | $ 501,534 |
Other operating income | 909 | 700 | 620 |
Total operating income | 827,697 | 866,467 | 504,917 |
Costs and expenses: | |||
Production and ad valorem taxes | 50,401 | 56,372 | 32,558 |
Depletion | 146,118 | 121,071 | 102,987 |
General and administrative expenses | 10,603 | 8,542 | 7,800 |
Other operating expense | 356 | 0 | 0 |
Total costs and expenses | 207,478 | 185,985 | 143,345 |
Income (loss) from operations | 620,219 | 680,482 | 361,572 |
Other income (expense): | |||
Interest expense, net | (48,907) | (40,409) | (34,044) |
Gain (loss) on derivative instruments, net | (25,793) | (18,138) | (69,409) |
Other income, net | 1,774 | 416 | 79 |
Total other expense, net | (72,926) | (58,131) | (103,374) |
Income (loss) before income taxes | 547,293 | 622,351 | 258,198 |
Provision for (benefit from) income taxes | 45,952 | (32,653) | 1,521 |
Net income (loss) | 501,341 | 655,004 | 256,677 |
Net income (loss) attributable to non-controlling interest | 301,253 | 503,331 | 198,738 |
Net income (loss) attributable to Viper Energy, Inc. | $ 200,088 | $ 151,673 | $ 57,939 |
Earnings Per Share [Abstract] | |||
Basic (dollars per shares) | $ 2.69 | $ 2 | $ 0.85 |
Diluted (dollars per shares) | $ 2.69 | $ 2 | $ 0.85 |
Weighted average number of common shares outstanding: | |||
Basic (in shares) | 74,176 | 75,612 | 68,319 |
Diluted (in shares) | 74,176 | 75,679 | 68,391 |
Revenue, Product and Service [Extensible Enumeration] | Royalty [Member] | Royalty [Member] | Royalty [Member] |
Related Party | |||
Operating income: | |||
Lease bonus income | $ 107,823 | $ 23,367 | $ 2,763 |
Nonrelated Party | |||
Operating income: | |||
Lease bonus income | $ 1,855 | $ 4,424 | $ 0 |
Statement of Consolidated Stock
Statement of Consolidated Stockholders’ Equity - USD ($) $ in Thousands | Total | Class A Shares | Class B Shares | General Partner | Non-Controlling Interest | Common Units Limited Partners | Class B Units Limited Partners | Common Stock Class A Shares | Common Stock Class B Shares | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Non-Controlling Interest | |||
Beginning balance (in shares) at Dec. 31, 2020 | 65,817,000 | 90,710,000 | |||||||||||||
Beginning balance at Dec. 31, 2020 | $ 1,860,833 | $ 809 | $ 1,225,578 | $ 633,415 | $ 1,031 | ||||||||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||||||||||||
Unit-based compensation | 1,172 | $ 1,172 | |||||||||||||
Common shares issued for acquisition (in shares) | 15,250,000 | ||||||||||||||
Common units issued for acquisition | 336,872 | $ 336,872 | |||||||||||||
Vesting of restricted stock units (in shares) | 92,000 | ||||||||||||||
Distribution equivalent rights payments | (193) | $ (193) | |||||||||||||
Distributions to public | (75,749) | (75,749) | |||||||||||||
Distributions to Diamondback | (100,685) | (99,782) | (803) | $ (100) | |||||||||||
Distributions to General Partner | (80) | (80) | |||||||||||||
Change in ownership of consolidated subsidiaries, net | 0 | 93,473 | (93,473) | ||||||||||||
Cash paid for tax withholding on vested common units | (20) | $ (20) | |||||||||||||
Repurchased units as part of unit buyback (in shares) | (2,613,000) | ||||||||||||||
Repurchased units as part of unit buyback | (45,999) | $ (45,999) | |||||||||||||
Net income (loss) | 57,939 | ||||||||||||||
Net income (loss) | 256,677 | 198,738 | $ 57,939 | ||||||||||||
Ending balance (in shares) at Dec. 31, 2021 | 78,546,000 | 90,710,000 | |||||||||||||
Ending balance at Dec. 31, 2021 | 2,232,828 | 729 | 1,418,007 | $ 813,161 | $ 931 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||
Common shares issued for acquisition (in shares) | 15,250,000 | ||||||||||||||
Common units issued for acquisition | 336,872 | $ 336,872 | |||||||||||||
Vesting of restricted stock units (in shares) | 92,000 | ||||||||||||||
Distribution equivalent rights payments | (193) | $ (193) | |||||||||||||
Distributions to public | (75,749) | (75,749) | |||||||||||||
Distributions to Diamondback | (100,685) | (99,782) | (803) | (100) | |||||||||||
Change in ownership of consolidated subsidiaries, net | 0 | 93,473 | (93,473) | ||||||||||||
Cash paid for tax withholding on vested common units | (20) | $ (20) | |||||||||||||
Repurchased units as part of unit buyback (in shares) | (2,613,000) | ||||||||||||||
Repurchased units as part of unit buyback | (45,999) | $ (45,999) | |||||||||||||
Net income (loss) | 256,677 | 198,738 | 57,939 | ||||||||||||
Unit-based compensation | 1,304 | $ 1,304 | |||||||||||||
Vesting of restricted stock units (in shares) | 79,000 | ||||||||||||||
Distribution equivalent rights payments | (365) | $ (365) | |||||||||||||
Distributions to public | (182,470) | (182,470) | |||||||||||||
Distributions to Diamondback | (234,103) | (232,219) | (1,785) | $ (99) | |||||||||||
Distributions to General Partner | (80) | (80) | |||||||||||||
Change in ownership of consolidated subsidiaries, net | 0 | (58,253) | $ 58,253 | ||||||||||||
Repurchased units as part of unit buyback (in shares) | (1,500,000) | (5,395,000) | |||||||||||||
Repurchased units as part of unit buyback | (150,593) | $ (37,300) | $ (150,593) | ||||||||||||
Net income (loss) | 151,673 | ||||||||||||||
Net income (loss) | 655,004 | 503,331 | $ 151,673 | ||||||||||||
Ending balance (in shares) at Dec. 31, 2022 | 73,230,000 | 90,710,000 | |||||||||||||
Ending balance at Dec. 31, 2022 | 2,321,525 | 649 | 1,630,866 | $ 689,178 | $ 832 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||
Vesting of restricted stock units (in shares) | 79,000 | ||||||||||||||
Distribution equivalent rights payments | (365) | $ (365) | |||||||||||||
Distributions to public | (182,470) | (182,470) | |||||||||||||
Distributions to Diamondback | (234,103) | (232,219) | (1,785) | $ (99) | |||||||||||
Change in ownership of consolidated subsidiaries, net | 0 | (58,253) | $ 58,253 | ||||||||||||
Repurchased units as part of unit buyback (in shares) | (1,500,000) | (5,395,000) | |||||||||||||
Repurchased units as part of unit buyback | (150,593) | $ (37,300) | $ (150,593) | ||||||||||||
Net income (loss) | 655,004 | $ 503,331 | $ 151,673 | ||||||||||||
Ending balance (in shares) at Dec. 31, 2022 | [1] | 0 | 0 | ||||||||||||
Ending balance at Dec. 31, 2022 | 2,321,525 | $ 0 | $ 0 | $ 1,630,866 | |||||||||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||||||||||||
Conversion of Viper Energy Partnership Units to Viper Energy Inc. Common Shares (in shares) | (78,126,000) | (90,710,000) | |||||||||||||
Conversion of Viper Energy Partnership Units to Viper Energy Inc. Common Shares | $ (937,468) | $ (757) | |||||||||||||
Common shares issued for acquisition (in shares) | [1] | 9,018,000 | |||||||||||||
Common units issued for acquisition | 254,600 | 254,600 | |||||||||||||
Common shares/units issued to related party (in shares) | 7,215,000 | ||||||||||||||
Common shares/units issued to related party | 200,000 | $ 200,000 | |||||||||||||
Vesting of restricted stock units (in shares) | 73,000 | ||||||||||||||
Distribution equivalent rights payments | (211) | $ (163) | (48) | ||||||||||||
Distributions to public | (128,566) | (84,018) | (44,548) | ||||||||||||
Distributions to Diamondback | (195,976) | (862) | $ (75) | (20) | (4,530) | (190,489) | |||||||||
Distributions to General Partner | (90) | (90) | |||||||||||||
Change in ownership of consolidated subsidiaries, net | 0 | $ 31,668 | (133,300) | 101,632 | |||||||||||
Repurchased units as part of unit buyback (in shares) | (1,000,000) | (2,392,000) | (1,000,000) | [1] | |||||||||||
Repurchased units as part of unit buyback | (95,221) | $ (67,181) | (28,040) | ||||||||||||
Net income (loss) | 200,088 | $ 167,748 | 32,340 | ||||||||||||
Net income (loss) | 501,341 | 301,253 | |||||||||||||
Ending balance (in shares) at Dec. 31, 2023 | 0 | 0 | |||||||||||||
Ending balance at Dec. 31, 2023 | 0 | $ 0 | $ 0 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||
Conversion of Viper Energy Partnership Units to Viper Energy Inc. Common Shares (in shares) | [1] | 78,126,000 | 90,710,000 | ||||||||||||
Conversion of Viper Energy Partnership Units to Viper Energy Inc. Common Shares | 0 | 938,225 | |||||||||||||
Liquidation of General Partner | (1,150) | $ (559) | (591) | ||||||||||||
Common shares issued for acquisition (in shares) | [1] | 9,018,000 | |||||||||||||
Common units issued for acquisition | 254,600 | 254,600 | |||||||||||||
Equity-based compensation | 1,302 | $ 1,098 | 204 | ||||||||||||
Vesting of restricted stock units (in shares) | 73,000 | ||||||||||||||
Distribution equivalent rights payments | (211) | $ (163) | (48) | ||||||||||||
Distributions to public | (128,566) | (84,018) | (44,548) | ||||||||||||
Distributions to Diamondback | (195,976) | (862) | $ (75) | (20) | (4,530) | (190,489) | |||||||||
Change in ownership of consolidated subsidiaries, net | 0 | $ 31,668 | (133,300) | 101,632 | |||||||||||
Repurchased units as part of unit buyback (in shares) | (1,000,000) | (2,392,000) | (1,000,000) | [1] | |||||||||||
Repurchased units as part of unit buyback | (95,221) | $ (67,181) | (28,040) | ||||||||||||
Net income (loss) | 501,341 | 301,253 | |||||||||||||
Ending balance (in shares) at Dec. 31, 2023 | 86,144,273 | 90,709,946 | 86,144,000 | [1] | 90,710,000 | [1] | |||||||||
Ending balance at Dec. 31, 2023 | $ 2,857,554 | $ 1,031,078 | $ (16,786) | $ 1,843,262 | |||||||||||
[1]The par values of the outstanding shares of Class A Common Stock and Class B Common Stock each round to zero at December 31, 2023 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 501,341 | $ 655,004 | $ 256,677 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Provision for (benefit from) deferred income taxes | (7,000) | (49,656) | 0 |
Depletion | 146,118 | 121,071 | 102,987 |
(Gain) loss on derivative instruments, net | 25,793 | 18,138 | 69,409 |
Net cash receipts (payments) on derivatives | (13,319) | (31,319) | (92,585) |
Other | 3,442 | 5,070 | 4,710 |
Changes in operating assets and liabilities: | |||
Royalty income receivable | (27,379) | (13,089) | (36,358) |
Royalty income receivable—related party | 2,931 | (4,116) | (146) |
Accounts payable and accrued liabilities | 6,311 | 151 | 2,273 |
Accounts payable—related party | 1,024 | 306 | 0 |
Income taxes payable | 1,014 | 440 | 471 |
Other | (2,084) | (2,204) | (324) |
Net cash provided by (used in) operating activities | 638,192 | 699,796 | 307,114 |
Cash flows from investing activities: | |||
Proceeds from sale of oil and natural gas interests | (3,164) | 111,702 | 0 |
Net cash provided by (used in) investing activities | (908,365) | 47,571 | (281,176) |
Cash flows from financing activities: | |||
Proceeds from borrowings under credit facility | 573,000 | 272,000 | 330,000 |
Repayment on credit facility | (462,000) | (424,000) | (110,000) |
Proceeds from senior notes | 400,000 | 0 | 0 |
Repayment of senior notes | 0 | (48,963) | 0 |
Proceeds from public offering to Diamondback | 200,000 | 0 | 0 |
Repurchased shares/units under buyback program | (95,221) | (150,593) | (45,999) |
Dividends/distributions to shareholders | (128,777) | (182,835) | (75,942) |
Dividends/distributions to Diamondback | (195,976) | (234,103) | (100,685) |
Other | (13,163) | (142) | (2,985) |
Net cash provided by (used in) financing activities | 277,863 | (768,636) | (5,611) |
Net increase (decrease) in cash and cash equivalents | 7,690 | (21,269) | 20,327 |
Cash, cash equivalents and restricted cash at beginning of period | 18,179 | 39,448 | 19,121 |
Cash, cash equivalents and restricted cash at end of period | 25,869 | 18,179 | 39,448 |
Supplemental disclosure of cash flow information: | |||
Interest paid | (40,187) | (36,868) | (30,784) |
Cash (paid) received for income taxes | (51,345) | (16,990) | (1,050) |
Supplemental disclosure of non—cash transactions: | |||
Common shares/units issued for acquisition | (254,600) | 0 | (336,872) |
Related Party | |||
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas interests | (75,073) | 0 | 0 |
Nonrelated Party | |||
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas interests | $ (830,128) | $ (64,131) | $ (281,176) |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Presentation | ORGANIZATION AND BASIS OF PRESENTATION Conversion into Corporation Effective November 13, 2023 (the “Effective Time”), Viper Energy Partners LP (the “Partnership”) converted from a publicly traded Delaware limited partnership to a Delaware corporation pursuant to a plan of conversion (the “Conversion”) and changed names from Viper Energy Partners LP to Viper Energy, Inc. Additionally, the certificate of incorporation and the bylaws of Viper Energy, Inc. became effective. This annual report includes the results for the Partnership prior to the Conversion and Viper Energy, Inc. (the “Company”) following the Conversion. References to the “Company” refer to (i) Viper Energy, Inc. and its consolidated subsidiaries following the Conversion and (ii) the Partnership and its consolidated subsidiaries prior to the Conversion. References to shares or per share amounts prior to the Conversion refer to units or per unit amounts. Unless otherwise noted, all references to shares or per share amounts following the Conversion refer to shares or per share amounts of Common Stock, as defined in the paragraph below. References to dividends prior to the Conversion refer to distributions. There are no tax impacts resulting from the Conversion as Viper Energy Partners LP was treated as a corporation for tax purposes. At the Effective Time, each common unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class A Common Stock, $0.000001 par value per share (“Class A Common Stock”), of the Company, (ii) each Class B unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class B Common Stock, $0.000001 par value per share, of the Company (“Class B Common Stock” and, together with Class A Common Stock, “Common Stock”), and (iii) the general partner interest issued and outstanding immediately prior to the Effective Time (100% owned by the General Partner) was cancelled and was no longer outstanding. At the Effective Time, as a result of the Conversion, holders of common units became holders of Class A Common Stock and holders of Class B units became holders of Class B Common Stock. Similar to Class B units before the Conversion, each share of Class B Common Stock is exchangeable, at the discretion of the holders of Class B Common Stock, together with one unit of the Operating Company, into one share of Class A Common Stock post-Conversion. Holders of Class B Common Stock have the same preferred dividend and liquidation preference rights as those provided to holders of Class B units under the Partnership Agreement. At the Effective Time, Diamondback Energy, Inc. (“Diamondback”) and its wholly owned subsidiary Diamondback E&P LLC were the only holders of the Class B Common Stock and collectively owned approximately 56% of the outstanding shares of Common Stock. As a result, the Company is a “controlled company” within the meaning of the corporate governance standards of Nasdaq and, as a result, will qualify for certain exemptions from the corporate governance rules of Nasdaq. After the Conversion, former limited partners owned the same percentage of the Company’s outstanding shares as they previously owned of the Partnership’s outstanding equity interests. At the Effective Time, the certificate of incorporation and bylaws of the Company generally provided stockholders of the Company with substantially the same or greater rights and substantially the same or lesser obligations, as those that limited partners had in the Partnership Agreement. Previously, limited partners were not generally entitled to vote with respect to governance of the Partnership, except for those few matters set forth in the Partnership Agreement. Following the Conversion, except as otherwise expressly provided in the Certificate of Incorporation, the holders of Common Stock are entitled to vote on all matters on which stockholders of a corporation are generally entitled to vote on under the Delaware General Corporation Law, including the election of the board of directors of the Company. As of the Effective Time, the business and affairs of the Company are overseen by a board of directors, rather than the General Partner, which previously oversaw the business and affairs of the Partnership as its general partner. The directors and executive officers of the General Partner immediately prior to the Effective Time became the directors and executive officers of the Company at the Effective Time. In addition, the audit committee of the board of directors of the General Partner, and the membership thereof, immediately prior to the Effective Time, were replicated at the Company at the Effective time. Further, post-Conversion, Diamondback continues to provide personnel and general and administrative services to the Company, including the services of the executive officers and other employees, pursuant to the services and secondment agreement in substantially the same manner as Diamondback previously provided to the General Partner. In addition, for so long as Diamondback and any of its subsidiaries collectively beneficially own at least 25% of the outstanding common stock of the Company, (i) Diamondback will have the right to designate up to three persons to serve as directors of the Company and (ii) the board of directors of the Company may not appoint any person other than a Diamondback seconded employee as an executive officer of the Company unless such appointment is approved, in advance, by either (x) Diamondback (which approval may not be unreasonably withheld or conditioned) or (y) the affirmative vote of the holders of at least 80% of the voting power of the capital stock of the Company. Currently, there are two Diamondback designees to the board of directors of the Company—Travis Stice and Kaes Van’t Hof. At the open of business on November 13, 2023, Nasdaq ceased trading of the common units and commenced trading of the Class A Common Stock on Nasdaq under the existing ticker symbol “VNOM,” and the Company became the successor registrant to the Partnership. No action by the current holders of common units was required. A new CUSIP number has been issued for the Class A Common Stock, which became effective at the Effective Time. Because the Partnership was already treated as a corporation for U.S. federal income tax purposes pre-Conversion, the Conversion did not affect the Company’s status as a corporation for U.S. federal income tax purposes or materially impact the U.S. federal income tax treatment of its common equity holders. Organization The Company is a publicly traded Delaware corporation focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin. As of December 31, 2023, Diamondback beneficially owned approximately 56% of the Company’s total Common Stock outstanding. Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation. Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates Certain amounts included in or affecting the Company’s 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 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 financial statements. 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, the war in Ukraine and the Israel-Hamas War, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and measures to combat persistent inflation and instability in the financial sector have contributed to recent pricing and economic volatility. The financial results of companies in the oil and natural gas industry have been and may continue to be impacted materially as a result of changing market conditions. Such circumstances generally increase 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 each particular circumstance. 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 interests, estimates of third party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties, the fair value determination of assets and liabilities, including those acquired by the Company, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. 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. Royalty Income Receivable Royalty income receivables consist of receivables for oil and natural gas sales made by the Company’s third-party operators and Diamondback. The operators remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work which is required to be completed by the operator before payments are released. Royalty income receivables are stated at amounts due from operators, net of an allowance for expected losses as estimated by the Company when collection is deemed doubtful. Royalty income receivables outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance utilizing the loss-rate method, which considers a number of factors, including 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 royalty income receivables when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2023 and December 31, 2022, the Company’s allowance for expected losses was immaterial. 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. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Company’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Company owns a royalty interest sells the Company’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Company collects its percentage royalty based on the revenue generated. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Company’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of the Company’s royalty income contracts. Contract balances Under the Company’s royalty income contracts, it has the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Company’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, 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 royalty income to be received based upon the Company’s interest. The Company records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. 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 royalties related to expected sales volumes and prices for those properties are estimated and recorded. 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 costs are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2023 and 2022, the Company’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $10.20, $9.86 and $10.04 for the years ended December 31, 2023, 2022 and 2021, respectively. Depletion for oil and natural gas properties was $146.1 million, $121.1 million and $103.0 million 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 interests net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (i) 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, (ii) the cost of properties not being amortized, if any, and (iii) 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. See Note 5— Oil and Natural Gas Interests for additional discussion of the Company’s oil and natural gas properties. 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 at least annually 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 of the operator to drill; remaining lease term with the current operator; 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. Debt Issuance Costs Other assets include capitalized costs related to the credit facility of $15.5 million and $9.7 million, and accumulated amortization of those costs over the term of the credit facility of $10.0 million and $9.5 million as of December 31, 2023, and 2022, respectively. Long-term debt includes capitalized costs related to t he Company’s 5.375% senior notes due 2027 and 7.375% senior notes due 2031 (collectively, th e “Notes”) . The costs associated with the Notes are being netted against the Notes’ balances and amortized over the term of the Notes using the effective interest method. See Note 6— Debt for further details. Related Party Transactions Royalty Income Receivable As of December 31, 2023 and December 31, 2022, Diamondback, either directly or through its consolidated subsidiaries, owed the Company $3.3 million and $6.3 million, respectively, for royalty income received from third parties for the Company’s production, which had not yet been remitted to the Company. Lease Bonus Income During the year ended December 31, 2023, Diamondback, either directly or through its consolidated subsidiaries, paid the Company $107.8 million of lease bonus income primarily related to new leases in the Permian Basin. Lease bonus income for the year ended December 31, 2023 includes a lease bonus payment of $95.8 million to the Operating Company from a lease agreement with a subsidiary of Diamondback covering certain Permian Basin acreage on terms substantially identical to the Operating Company’s other lease arrangements with Diamondback. This transaction was considered and approved by the conflicts committee of the board of directors. During the year ended December 31, 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Company $23.4 million of lease bonus income primarily related to lease ratification and certain leases acquired in the Swallowtail Acquisition. Other Related Party Transactions See Note 4— Ac quisitions and Divestitures for significant related party acquisitions of oil and natural gas interests. See Note 7— Stockholders' Equity for further details regarding equity transactions with related parties. All other related party transactions with Diamondback or its affiliates have been stated on the face of the consolidated financial statements or were insignificant for the years ended December 31, 2023, 2022 and 2021, respectively. Accrued Liabilities The Company’s accrued liabilities are financial instruments for which the carrying value approximates fair value. Accrued liabilities consist of the following at December 31, 2023, and 2022: December 31, 2023 2022 (In thousands) Interest payable $ 11,036 $ 3,972 Ad valorem taxes payable 13,299 12,492 Derivatives instruments payable 1,279 1,684 Other 1,407 1,452 Total accrued liabilities $ 27,021 $ 19,600 Concentrations The Company is subject to risk resulting from the concentration of the Company’s royalty income in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2023, two purchasers each accounted for more than 10% of royalty income: Vitol Midstream Pipeline LLC (16%) and DK Trading and Supply LLC (15%). For the year ended December 31, 2022, two purchasers each accounted for more than 10% of royalty income: Shell Trading (US) Company (14%) and Vitol Midstream Pipeline LLC (14%). For the year ended December 31, 2021, three purchasers each accounted for more than 10% of royalty income: Trafigura Trading LLC (17%), Shell Trading (US) Company (16%) and Vitol Midstream Pipeline LLC (12%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact the Company’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. 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. 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, 2022 and 2021, there were no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. See Note 9— Income Taxes for further details. Non-controlling Interest Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and stockholders’ equity, tax effected, will occur. Because these changes in the Company’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Company’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 7— Stockholders' Equity for further discussion of changes in ownership interest. Recent Accounting Pronouncements Recently Adopted Pronouncements There are no recently adopted pronouncements. Accounting Pronouncements Not Yet Adopted 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 fiscal years 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. |
REVENUE FROM CONTRACTS WITH CUS
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 Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index. For the years ended December 31, 2023, 2022 and 2021, any revenues recognized in the current reporting period for performance obligations satisfied in prior reporting periods were not material. The following table disaggregates the Company’s total royalty income by product type: Year Ended December 31, 2023 2022 2021 (In thousands) Oil income $ 619,181 $ 667,281 $ 397,513 Natural gas income 30,953 83,149 49,197 Natural gas liquids income 66,976 87,546 54,824 Total royalty income $ 717,110 $ 837,976 $ 501,534 |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended |
Dec. 31, 2023 | |
Business Combinations And Divestitures [Abstract] | |
ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES 2023 Activity Acquisitions GRP Acquisition On November 1, 2023, the Company and the Operating Company acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP, affiliates of Warwick Capital Partners and GRP Energy Capital (collectively, “GRP”) pursuant to a definitive purchase and sale agreement for approximately 9.02 million common units and $759.6 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 approximately 4,600 net royalty acres in the Permian Basin, plus approximately 2,700 additional 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 Operating Company’s revolving credit facility, proceeds from the 2031 Notes (as defined in Note 6— Debt ) and proceeds from the $200.0 million common unit issuance to Diamondback discussed further in Note 7— Stockholders' Equity . Drop Down Transaction On March 8, 2023, the Company acquired certain mineral and royalty interests from subsidiaries of Diamondback for approximately $74.5 million in cash, including customary closing adjustments for net title benefits (the “Drop Down”). The mineral and royalty interests acquired in the Drop Down represent approximately 660 net royalty acres in Ward County in the Southern Delaware Basin, 100% of which are operated by Diamondback, and have an average net royalty interest of approximately 7.2% and current production of approximately 300 BO/d. The Company funded the Drop Down through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. The Drop Down was accounted for as a transaction between entities under common control with the properties acquired recorded at Diamondback’s historical carrying value in the Company’s consolidated balance sheet. The historical carrying value of the properties approximated the Drop Down purchase price. Other Acquisitions Additionally during the year ended December 31, 2023 the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 286 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $70.4 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. 2022 Activity Acquisitions During the year ended December 31, 2022, in individually insignificant transactions, the Company acquired from unrelated third-party sellers mineral and royalty interests representing 375 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $65.8 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. Divestitures In the fourth quarter of 2022, the Company divested its entire position in the Eagle Ford Shale consisting of 681 net royalty acres of third party operated acreage for an aggregate net sales price of $53.7 million, including customary closing adjustments. In the third quarter of 2022, the Company divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate net sales price of $29.9 million, including customary closing adjustments. In the first quarter of 2022, the Company divested 325 net royalty acres of third party operated acreage located entirely in Upton and Reagan counties in the Midland Basin for an aggregate net sales price of $29.3 million, including customary closing adjustments. 2021 Acquisitions Swallowtail Acquisition On October 1, 2021 , the Company and the Operating Company acquired certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC (the “Swallowtail entities”) pursuant to a definitive purchase and sale ag reement for approximately 15.25 million common shares and approximately $225.3 million in cash (the “Swallowtail Acquisition” ). The mineral and royalty interests acquired in the Swallowtail Acquisition represent 2,313 net royalty acres primarily in the Northern Midland Basin, of which 62% are operated by Diamondback. The Swallowtail Acquisition had an effective date of August 1, 2021. The cash portion of this transaction was funded through a combination of cash on hand and approximately $190.0 million of borrowings under the Operating Company’s revolving credit facility. Other 2021 Acquisitions Additionally during the year ended December 31, 2021, the Company acquired, from unrelated third party sellers, mineral and royalty interests representing 392 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $55.1 million, after post-closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. |
OIL AND NATURAL GAS INTERESTS
OIL AND NATURAL GAS INTERESTS | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
OIL AND NATURAL GAS INTERESTS | OIL AND NATURAL GAS INTERESTS Oil and natural gas interests include the following: December 31, 2023 2022 (In thousands) Oil and natural gas interests: Subject to depletion $ 2,859,642 $ 2,167,598 Not subject to depletion 1,769,341 1,297,221 Gross oil and natural gas interests 4,628,983 3,464,819 Accumulated depletion and impairment (866,352) (720,234) Oil and natural gas interests, net 3,762,631 2,744,585 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 3,768,319 $ 2,750,273 Balance of costs not subject to depletion: Incurred in 2023 $ 720,529 Incurred in 2022 33,781 Incurred in 2021 429,991 Prior 585,040 Total not subject to depletion $ 1,769,341 As of December 31, 2023 and 2022, the Company had mineral and royalty interests representing 34,217 and 26,315 net royalty acres, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves can be made. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within eight Based on the results of the quarterly ceiling tests, the Company was not required to record an impairment on the Company’s proved oil and natural gas interests for the years ended December 31, 2023, 2022 and 2021. In addition to commodity prices, the Company’s production rates, levels of proved reserves, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If the trailing 12-month commodity prices were to fall as compared to the com modity prices used in prior quarters, the Company could have write-downs in subsequent quarters, which may be material. |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
DEBT | DEBT Long-term debt consisted of the following as of the dates indicated: December 31, 2023 2022 (In thousands) 5.375% senior unsecured notes due 2027 $ 430,350 $ 430,350 7.375% senior unsecured notes due 2031 400,000 — Revolving credit facility 263,000 152,000 Unamortized debt issuance costs (6,903) (1,306) Unamortized discount (3,365) (4,149) Total long-term debt $ 1,083,082 $ 576,895 Issuance of 2031 Notes On October 19, 2023, the Company completed an offering of $400.0 million in aggregate principal amount of its 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”). The Company received net proceeds of approximately $394.0 million, after deducting the initial purchasers’ discount and transaction costs from the 2031 Notes. The Company loaned the gross proceeds to the Operating Company, which used the proceeds to partially fund the cash portion of the GRP Acquisition. The Notes The Notes are senior unsecured obligations of the Company, initially guaranteed on a senior unsecured basis by the Operating Company, and will pay interest semi-annually. Diamondback will not guarantee the Notes. In the future, each of the Company’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 Notes. The Operating Company’s Revolving Credit Facility On May 31, 2023, the Operating Company entered into a tenth amendment to the existing credit facility, which among other things, (i) maintained the maximum credit amount of $2.0 billion, (ii) increased the borrowing base from $580.0 million to $1.0 billion and (iii) increased the aggregate elected commitment amount from $500.0 million to $750.0 million. On September 22, 2023, the Operating Company entered into an eleventh and separately a twelfth amendment to the existing credit facility, 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 upon consummation of the GRP Acquisition, (iv) further increased the aggregate elected commitment amount from $750.0 million to $850.0 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, the Operating Company had $263.0 million of outstanding borrowings and $587.0 million available for future borrowings under the Operating Company’s revolving cred it facility. For the years ended December 31, 2023, 2022 and 2021, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was 7.41% , 4.22%, and 2.35% , respectively. The outstanding borrowings under the credit facility bear interest at a rate elected by the Operating Company 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 1.00%), 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. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment. The credit facility is secured by substantially all the assets of the Company and the Operating Company. The credit facility 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 credit facility Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit facility Not less than 1.0 to 1.0 Ratio of secured debt to EBITDAX, as defined in the credit facility Not greater than 2.5 to 1.0 As of December 31, 2023, the Operating Company was in compliance with all financial maintenance covenants under its credit facility. 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 thousands) Interest expense $ 48,222 $ 37,539 $ 31,384 Other fees and expenses 836 2,883 2,662 Less: interest income 151 13 2 Interest expense, net $ 48,907 $ 40,409 $ 34,044 |
STOCKHOLDERS_ EQUITY
STOCKHOLDERS’ EQUITY | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
STOCKHOLDERS’ EQUITY | STOCKHOLDERS’ EQUITY At December 31, 2023, the Company had a total of 86,144,273 shares of Class A Common Stock issued and outstanding and 90,709,946 shares of Class B Common Stock issued and outstanding, of which 7,946,507 shares of Class A Common Stock and 90,709,946 shares of Class B Common Stock were beneficially owned by Diamondback, representing approximately 56% of the Company’s total shares outstanding. Diamondback also beneficially owns 90,709,946 Operating Company shares, representing a 51% non-controlling ownership interest in the Operating Company. The Operating Company shares and the Company’s Class B Common Stock beneficially owned by Diamondback are exchangeable from time to time for the Company’s Class A Common Stock (that is, one Operating Company share and one Company Class B Common Stock share, together, will be exchangeable for one Company Class A Common Stock share). Viper Issuance of Common Units to Diamondback On October 31, 2023, the Company issued approximately 7.22 million of its common units to Diamondback at a price of $27.72 per unit for total net proceeds of approximately $200.0 million pursuant to a common unit purchase and sale agreement entered into with Diamondback on September 4, 2023. The net proceeds of this common unit issuance were used to fund a portion of the cash consideration for the GRP Acquisition. Common Stock Repurchase Program The board of directors of the General Partner previously authorized a $750.0 million common unit repurchase program, which has been ratified and continued by the Company’s board of directors with respect to the repurchase of the Company’s Class A Common Stock, excluding excise tax, over an indefinite period of time. The Company intends to purchase shares of Class A Common Stock un der the repurchase program opportunistically with funds from cash on hand, free cash flow from operatio ns and potential l iquidity events such as the sale of assets. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the Company at any time. During the years ended December 31, 2023, 2022 and 2021, repurchases under the repurchase program totaled $95.2 million, $150.6 million, and $46.0 million, respectively. Repurchases for the year ended December 31, 2023 include approximately $28.7 million for the repurchase of 1.0 million shares of Class A Common Stock from GRP in a privately negotiated transaction in the fourth quarter of 2023. Repurchases for the year ended December 31, 2022 include approximately $37.3 million for the repurchase of 1.5 million shares of Class A Common Stock from a significant shareholder in a privately negotiated transaction. As of December 31, 2023, $434.2 million remains available under the repurchase program, excluding excise tax. Changes in Ownership of Consolidated Subsidiaries Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. Diamondback’s relative ownership interest in the Operating Company can change due to the Company’s public offerings of shares, issuance of shares for acquisitions, issuance of share-based compensation, repurchases of common shares and distribution equivalent rights paid on the Company’s shares. These changes in ownership percentage result in adjustments to non-controlling interest and stockholders’ equity, tax effected, but do not impact earnings. The following table summarizes the changes in stockholders’ equity due to changes in ownership interest during the period: Year Ended December 31, 2023 2022 2021 (In thousands) Net income (loss) attributable to the Company $ 200,088 $ 151,673 $ 57,939 Change in ownership of consolidated subsidiaries (101,632) 58,253 (93,473) Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest $ 98,456 $ 209,926 $ (35,534) Cash Dividends The board of directors of the Company has established a dividend policy, consistent with the pre-Conversion distribution policy, whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to its unitholders (including Diamondback and the Company) and the Company in turn distributes all or a portion of the available cash it receives from the Operating Company to shareholders of its Class A Common Stock. The Company currently intends to pay quarterly variable dividends of at least 75% of its available cash less the base dividend declared and the amount paid in stock repurchases as part of the Company’s buyback program for the applicable quarter. Additionally, the Company’s board of directors approved excluding the $28.7 million one-time share repurchase from GRP that occurred in November 2023 from the calculation of cash available for distribution for the fourth quarter of 2023. The Company’s available cash and the available cash of the Operating Company for each quarter, a non-GAAP measure, is determined by the Company’s board of directors following the end of such quarter. The Company expects that its available cash will generally equal the Adjusted EBITDA attributable to the Company for the applicable quarter, less cash needed for income taxes payable, debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that the Company’s board of directors deems necessary or appropriate, lease bonus income (net of applicable taxes), distribution equivalent rights payments and preferred distributions. The percentage of cash available for distribution by the Operating Company pursuant to the distribution policy may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Company’s balance sheet while also expanding the return of capital program through the Company’s stock repurchase program. The Company is also required to pay a quarterly preferred dividend in respect of its Class B Common Stock in the aggregate amount of $20,000 per quarter, which is consistent with the Partnership’s pre-Conversion preferred distribution requirement. Other than the preferred dividend requirement, the Company is not required to pay dividends to its common stockholders on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of the Company’s board of directors. The following table presents information regarding cash distributions and dividends paid during the years ended December 31, 2023, 2022 and 2021 (in thousands, except for per unit amounts): Period Amount per Operating Company Unit Operating Company Distributions to Diamondback Amount per Common Unit Common Unitholders (1) Declaration Date Unitholder Record Date Payment Date Q4 2020 $ 0.14 $ 12,699 $ 0.14 $ 9,162 February 19, 2021 March 4, 2021 March 11, 2021 Q1 2021 $ 0.25 $ 22,678 $ 0.25 $ 16,230 April 27, 2021 May 13, 2021 May 20, 2021 Q2 2021 $ 0.33 $ 29,936 $ 0.33 $ 21,235 July 28, 2021 August 12, 2021 August 19, 2021 Q3 2021 $ 0.38 $ 34,469 $ 0.38 $ 30,118 October 27, 2021 November 11, 2021 November 18, 2021 Q4 2021 $ 0.47 $ 42,634 $ 0.47 $ 36,238 February 16, 2022 March 4, 2022 March 11, 2022 Q1 2022 $ 0.70 $ 63,497 $ 0.67 $ 51,680 April 27, 2022 May 12, 2022 May 19, 2022 Q2 2022 $ 0.87 $ 78,918 $ 0.81 $ 60,626 July 26, 2022 August 16, 2022 August 23, 2022 Q3 2022 $ 0.52 $ 47,170 $ 0.49 $ 36,076 November 3, 2022 November 17, 2022 November 25, 2022 Q4 2022 $ 0.54 $ 48,983 $ 0.49 $ 35,683 February 15, 2023 March 3, 2023 March 10, 2023 Q1 2023 $ 0.42 $ 38,097 $ 0.33 $ 23,797 April 26, 2023 May 11, 2023 May 18, 2023 Q2 2023 $ 0.44 $ 39,912 $ 0.36 $ 25,563 July 25, 2023 August 10, 2023 August 17, 2023 Q3 2023 $ 0.70 $ 63,497 $ 0.57 $ 49,126 November 2, 2023 November 16, 2023 November 24, 2023 (1) Payments made prior to the Conversion include amounts paid to Diamondback for the 731,500 common units then beneficially owned by Diamondback. Payments made after the Conversion include amounts paid to shareholders of Class A Common Stock, including the 7,946,507 shares of Class A Common Stock owned by Diamondback. Cash dividends will be made to the common stockholders of record on the applicable record date, generally within 60 days after the end of each quarter. Allocation of Net Incom e The Partnership, as the previous managing member of the Operating Company, had an agreement, as amended on December 28, 2021, whereby special allocations of the Operating Company’s income and gains over losses and deductions (but before depletion) were made to Diamondback through December 31, 2022. These special income allocations reduced the taxable income allocated to the Partnership’s common unitholders during 2022 and 2021. |
EARNINGS PER COMMON SHARE
EARNINGS PER COMMON SHARE | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
EARNINGS PER COMMON SHARE | EARNINGS PER COMMON SHARE The net income (loss) per share of Class A Common Stock on the consolidated statements of operations is based on the net income (loss) attributable to the Company’s Class A Common Stock for the year ended December 31, 2023, and common units for the years ended December 31, 2022 and 2021. For the years ended December 31, 2022 and 2021, the Partnership’s net income (loss) was allocated wholly to the common unitholders, as the General Partner did not have an economic interest. Payments made to the Company’s stockholders are determined in relation to the cash dividend policy described in Note 7— Stockholders' Equity . Basic and diluted earnings per share of the Company’s Class A Common Stock are calculated using the two-class method. The two-class method is an earnings allocation proportional to the respective ownership among holders of Class A Common Stock and participating securities. Basic net income (loss) per share of Class A Common Stock is calculated by dividing net income (loss) by the weighted-average shares of Class A Common Stock outstanding during the period. Diluted net income (loss) per share of Class A Common Stock gives effect, when applicable, to unvested shares of Class A Common Stock granted under the LTIP. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Year Ended December 31, 2023 2022 2021 (In thousands, except per share amounts) Net income (loss) attributable to the period $ 200,088 $ 151,673 $ 57,939 Less: net income (loss) allocated to participating securities (1) 299 365 193 Net income (loss) attributable to common stockholders $ 199,789 $ 151,308 $ 57,746 Weighted average common shares outstanding: Basic weighted average common shares outstanding 74,176 75,612 68,319 Effect of dilutive securities: Potential common shares issuable (2) — 67 72 Diluted weighted average common shares outstanding 74,176 75,679 68,391 Net income (loss) per common stock, basic $ 2.69 $ 2.00 $ 0.85 Net income (loss) per common stock, diluted $ 2.69 $ 2.00 $ 0.85 (1) Unvested restricted stock shares that contain non-forfeitable distribution equivalent rights granted are considered participating securities and therefore are included in the earnings per share calculation pursuant to the two-class method. (2) For the years ended December 31, 2023 and 2022, no significant potential common shares were excluded from the computation of diluted earnings per common share. For the year ended December 31, 2021, 10,160 potential common shares were excluded in the computation of diluted earnings per common share because their inclusion would have been anti-dilutive. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The Company’s total income tax expense and benefit for the years ended December 31, 2023 and 2022, respectively, differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of reductions to the valuation allowance in 2023 and in 2022. For the year ended December 31, 2021, total income tax expense differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and maintaining a valuation allowance on the Company’s deferred tax assets. The components of the provision for income taxes and effective tax rates for the years ended December 31, 2023, 2022 and 2021 are as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Current income tax provision (benefit): Federal $ 50,414 $ 15,929 $ 1,218 State 2,538 1,074 303 Total current income tax provision (benefit) 52,952 17,003 1,521 Deferred income tax provision (benefit): Federal (6,532) (49,656) — State (468) — — Total deferred income tax provision (benefit) (7,000) (49,656) — Total provision (benefit) from income taxes $ 45,952 $ (32,653) $ 1,521 Effective tax rates 8.4 % (5.2) % 0.6 % A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Income tax expense (benefit) at the federal statutory rate (21%) $ 114,931 $ 130,694 $ 54,221 Impact of nontaxable noncontrolling interest (63,263) (105,699) (41,735) State income tax expense (benefit), net of federal tax effect 1,657 846 262 Change in valuation allowance (7,281) (58,443) (11,175) Other, net (92) (51) (52) Provision for (benefit from) income taxes $ 45,952 $ (32,653) $ 1,521 The components of the Company’s deferred tax assets and liabilities as of December 31, 2023 and 2022 are as follows: Year Ended December 31, 2023 2022 (In thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 15 $ 70 Investment in the Operating Company 170,164 148,003 Total deferred tax assets 170,179 148,073 Valuation allowance (113,523) (98,417) Net deferred tax assets 56,656 49,656 Net deferred tax assets (liabilities) $ 56,656 $ 49,656 At December 31, 2023, the Company has net deferred tax assets of approximately $56.7 million, including immaterial federal capital loss carryforwards expiring in 2026 and immaterial state operating loss carryforwards. Deferred taxes are provided on the difference between the Company’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in the Operating Company. During the years ended December 31, 2023 and 2022, the Company recognized discrete income tax benefits of $7.0 million and $49.7 million, respectively, related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years. The Company principally operates in the state of Texas. For the years ended December 31, 2023 and 2022, the Company recognized $2.5 million and $1.1 million, respectively, in state income tax expense primarily for its share of Texas margin tax attributable to the Company’s results which are included in a combined tax return filed by Diamondback. At December 31, 2023, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The Company’s 2020 through 2023 tax years remain open to examination by tax authorities. The Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, and imposed an excise tax of 1% on the fair market value of certain public company stock repurchases for tax years beginning after December 31, 2022, and included several other provisions applicable to U.S. income taxes for corporations. The Company did not accrue excise tax during the year ended December 31, 2023 due to stock issuances exceeding stock repurchases for the year. |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVES | DERIVATIVES During 2023, the Company used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At December 31, 2023, the Company has puts, costless collars and fixed price basis swap contracts outstanding. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with put contracts for oil based on WTI Cushing and fixed price basis swaps for oil based on the spread between the WTI Cushing crude oil price and the Argus WTI Midland crude oil price. The Company’s fixed price basis swaps for natural gas are for the spread between the Waha Hub natural gas price and the Henry Hub natural gas price. The weighted average differential represents the amount of reduction to the WTI Cushing oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. Under the Company’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Company, and when the settlement price is above the ceiling price, the Company is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required. By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are all participants in the amended and restated credit facility, which is secured by substantially all of the assets of the Operating Company; therefore, the Company is not required to post any collateral. The Company’s counterparties have been determined to have an acceptable credit risk; therefore, the Company does not require collateral from its counterparties. As of December 31, 2023, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. Swaps Collars Puts Settlement Month Settlement Year Type of Contract Bbls/MMBtu Per Day Index Weighted Average Differential Weighted Average Floor Price Weighted Average Ceiling Price Strike Price Deferred Premium OIL Jan. - Mar. 2024 Puts 16,000 WTI Cushing $— $— $— $58.13 $(1.54) Apr. - Jun. 2024 Puts 14,000 WTI Cushing $— $— $— $59.29 $(1.51) Jul. - Dec. 2024 Puts 2,000 WTI Cushing $— $— $— $55.00 $(1.53) Jan. - Jun. 2024 Costless Collar 6,000 WTI Cushing $— $65.00 $95.55 $— $— Jul. - Dec. 2024 Costless Collar 4,000 WTI Cushing $— $55.00 $93.66 $— $— NATURAL GAS Jan. - Dec. 2024 Basis Swaps 30,000 Waha Hub $(1.20) $— $— $— $— Jan. - Dec. 2025 Basis Swaps 40,000 Waha Hub $(0.68) $— $— $— $— 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 11— Fair Value Measurements for further details. Gains and Losses on Derivative Instruments The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Gain (loss) on derivative instruments $ (25,793) $ (18,138) $ (69,409) Net cash receipts (payments) on derivatives (1) $ (13,319) $ (31,319) $ (92,585) (1) The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis on the Company’s consolidated balance sheets, including the Company’s derivative instruments. The fair values of the Company’s 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. These valuations are Level 2 in puts in the fair value hierarchy. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 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 thousands) Assets: Current: Derivative instruments $ — $ 7,040 $ — $ 7,040 $ (6,682) $ 358 Non-current: Derivative instruments $ — $ 1,269 $ — $ 1,269 $ (1,177) $ 92 Liabilities: Current: Derivative instruments $ — $ 9,643 $ — $ 9,643 $ (6,682) $ 2,961 Non-current: Derivative instruments $ — $ 1,378 $ — $ 1,378 $ (1,177) $ 201 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 thousands) Assets: Current: Derivative instruments $ — $ 13,296 $ — $ 13,296 $ (3,968) $ 9,328 Non-current: Derivative instruments $ — $ 1,911 $ — $ 1,911 $ (1,469) $ 442 Liabilities: Current: Derivative instruments $ — $ 3,968 $ — $ 3,968 $ (3,968) $ — Non-current: Derivative instruments $ — $ 1,476 $ — $ 1,476 $ (1,469) $ 7 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 Value Fair Value Carrying Value Fair Value (In thousands) Debt: Revolving credit facility $ 263,000 $ 263,000 $ 152,000 $ 152,000 5.375% senior notes due 2027 (1) $ 425,949 $ 422,122 $ 424,895 $ 411,634 7.375% senior notes due 2031 (1) $ 394,133 $ 418,408 $ — $ — (1) The carrying value includes associated deferred loan costs and any discount. The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the December 31, 2023 quoted market price, 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 mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of the Company’s proved oil and natural gas interests to fair value when they are impaired or held for sale. See Note 2— Summary of Significant Accounting Policies and Note 5— Oil and Natural Gas Interests for further discussion of non-recurring fair value adjustments. Fair Value of Financial Assets The Company has other financial instruments consisting of cash and cash equivalents, royalty income receivable, income tax receivable, prepaid expenses, other assets, accounts payable, accrued liabilities and income taxes payable. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES The Company is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business. While the ultimate outcome of any pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2023 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENTS Cash Dividend On February 15, 2024, the board of directors of the Company approved a cash dividend for the fourth quarter of 2023 of 0.56 per share of Class A Common Stock and $0.69 per Operating Company unit, in each case, payable on March 12, 2024, to stockholders of record at the close of business on March 5, 2024. The dividend on Class A Common Stock consists of a base quarterly dividend of $0.27 per share and a variable quarterly dividend of $0.29 per share. |
SUPPLEMENTAL INFORMATION ON OIL
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [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 and amortization are as follows: December 31, 2023 2022 (In thousands) Oil and natural gas interests: Proved $ 2,859,642 $ 2,167,598 Unproved 1,769,341 1,297,221 Total oil and natural gas interests 4,628,983 3,464,819 Accumulated depletion and impairment (866,352) (720,234) Net oil and natural gas interests capitalized $ 3,762,631 $ 2,744,585 Costs incurred in oil and natural gas activities Costs incurred in oil and natural gas property acquisition activities are as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Acquisition costs: Proved properties $ 402,659 $ 46,307 $ 138,882 Unproved properties 758,342 16,624 479,041 Total $ 1,161,001 $ 62,931 $ 617,923 Results of Operations from Oil and Natural Gas Producing Activities Substantially all of the Company’s producing activities are from oil and natural gas activities and are included in the “— Consolidated Statements of Operations ” above. Oil and Natural Gas Reserves Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers, as of December 31, 2023 and 2022 and prepared by Ryder Scott as of December 31, 2021. The reserve estimates represent the Company’s net revenue interest in the Company’s properties. 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 ended 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. All of the Company’s proved reserves included in the reserve reports are located in the continental United States. Although the estimates are believed to be 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 estimated proved reserves, which were prepared in accordance with the rules and regulations of the SEC. Oil Natural Gas Natural Gas Liquids Total (MBOE) (1) Proved Developed and Undeveloped Reserves: As of December 31, 2020 57,530 119,450 21,953 99,392 Purchase of reserves in place 5,246 9,549 2,264 9,102 Extensions and discoveries 17,256 39,256 7,182 30,981 Revisions of previous estimates (4,544) 29,788 (1,339) (918) Divestitures (180) (681) (114) (409) Production (6,068) (13,672) (1,913) (10,260) As of December 31, 2021 69,240 183,690 28,033 127,888 Purchase of reserves in place 599 1,186 209 1,006 Extensions and discoveries 15,714 29,177 5,281 25,858 Revisions of previous estimates 1,453 15,248 4,483 8,477 Divestitures (905) (3,469) (564) (2,047) Production (7,097) (15,868) (2,540) (12,282) As of December 31, 2022 79,004 209,964 34,902 148,900 Purchase of reserves in place 10,469 27,011 4,006 18,977 Extensions and discoveries 13,636 34,632 6,150 25,558 Revisions of previous estimates (5,178) 11,101 3,466 138 Production (8,028) (19,130) (3,108) (14,324) As of December 31, 2023 89,903 263,578 45,416 179,249 Proved Developed Reserves: December 31, 2021 49,280 134,485 19,476 91,170 December 31, 2022 54,817 161,119 25,621 107,291 December 31, 2023 69,043 221,462 37,417 143,371 Proved Undeveloped Reserves: December 31, 2021 19,960 49,205 8,557 36,718 December 31, 2022 24,187 48,845 9,281 41,609 December 31, 2023 20,860 42,116 7,999 35,878 (1) Includes total proved reserves of 91,417 MBOE, 81,895 MBOE, 69,060 MBOE and 57,647 MBOE as of December 31, 2023, 2022, 2021 and 2020, respectively, attributable to a non-controlling interest in the Company. 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 total extensions and discoveries of 25,558 MBOE resulted primarily from the drilling of 904 new wells and from 179 new proved undeveloped locations added. The Company’s total positive revisions of previous estimated quantities of 138 MBOE consist of positive revisions of 5,688 MBOE primarily attributable to performance revisions which were largely offset by PUD downgrades of 5,548 MBOE. Total purchases of reserves in place of 18,977 MBOE resulted primarily from the GRP Acquisition and other acquisitions of certain mineral and royalty interests. During the year ended December 31, 2022, the Company’s total extensions and discoveries of 25,858 MBOE resulted primarily from the drilling of 636 new wells and from 199 new proved undeveloped locations added. The Company’s total positive revisions of previous estimated quantities of 8,477 MBOE were due to positive revisions of 15,484 MBOE attributable to price and performance revisions which were largely offset by PUD downgrades of 7,007 MBOE. Total purchases of reserves in place of 1,006 MBOE resulted from multiple acquisitions of certain mineral and royalty interests. During the year ended December 31, 2021, the Company’s total extensions and discoveries of 30,981 MBOE resulted primarily from the drilling of 407 new wells and from 336 new proved undeveloped locations added. The Company’s total negative revisions of previous estimated quantities of 918 MBOE were due to PUD downgrades of 11,263 MBOE which were largely offset by positive revisions of 10,345 MBOE attributable to price and performance revisions. Total purchases of reserves in place of 9,102 MBOE resulted from multiple acquisitions of certain mineral and royalty interests, including the Swallowtail Acquisition. Proved Undeveloped Reserves As of December 31, 2023, the Company’s PUD reserves totaled 20,860 MBbls of oil, 42,116 MMcf of natural gas and 7,999 MBbls of natural gas liquids, for a total of 35,878 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. The Company’s PUD reserves were from 529 horizontal wells, all of which Diamondback operates. Of the horizontal locations, 154 are Middle Spraberry/Jo Mill wells, 140 are Wolfcamp A wells, 120 are Lower Spraberry wells, 74 are Wolfcamp B wells, 35 are Bone Spring wells and six are Dean wells. The following table includes the changes in PUD reserves for 2023: (MBOE) Beginning proved undeveloped reserves at December 31, 2022 41,609 Undeveloped reserves transferred to developed (13,021) Revisions (5,341) Purchases 2,534 Extensions and discoveries 10,097 Ending proved undeveloped reserves at December 31, 2023 35,878 The decrease in PUD reserves was primarily attributable to the conversion of 13,021 MBOE of PUD reserves into proved developed reserves and downward revisions of 5,341 MBOE primarily attributable to PUD downgrades of 5,548 MBOE. These reductions in PUD reserves were partially offset by positive additions of 10,097 MBOE, primarily from 179 new horizontal well locations attributable to extensions resulting from strategic drilling of wells to delineate our acreage position and acquisitions of 2,534 MBOE. All of the Company’s PUD drilling locations are scheduled to be drilled within five years from the date they were initially recorded. As of December 31, 2023, none of the Company’s total proved reserves were classified as proved developed non-producing. Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows is based on SEC Prices. 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 thousands) Future cash inflows $ 8,493,617 $ 10,072,969 $ 5,763,433 Future production taxes (593,840) (729,256) (416,761) Future income tax expense (934,392) (1,465,160) (572,991) Future net cash flows 6,965,385 7,878,553 4,773,681 10% discount to reflect timing of cash flows (3,778,499) (4,424,457) (2,680,564) Standardized measure of discounted future net cash flows (1) $ 3,186,886 $ 3,454,096 $ 2,093,117 (1) Includes a 51%, 55% and 54% non-controlling interest in the Company at December 31, 2023, 2022 and 2021, respectively. The following table 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) $ 77.93 $ 95.04 $ 64.87 Natural gas (per Mcf) $ 1.54 $ 5.74 $ 2.97 Natural gas liquids (per Bbl) $ 23.79 $ 38.95 $ 25.93 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 thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 3,454,096 $ 2,093,117 $ 1,023,594 Purchase of minerals in place 473,742 30,331 170,205 Divestiture of reserves — (30,076) (4,402) Sales of oil and natural gas, net of production costs (666,709) (781,604) (468,976) Extensions and discoveries 626,854 844,010 615,762 Net changes in prices and production costs (1,405,205) 1,131,202 863,458 Revisions of previous quantity estimates 2,726 309,338 45,788 Net changes in income taxes 212,391 (393,652) (243,186) Accretion of discount 427,998 234,717 103,446 Net changes in timing of production and other 60,993 16,713 (12,572) Standardized measure of discounted future net cash flows at the end of the period $ 3,186,886 $ 3,454,096 $ 2,093,117 |
Pay vs Performance Disclosure
Pay vs Performance Disclosure - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Pay vs Performance Disclosure | |||
Net income (loss) attributable to the period | $ 200,088 | $ 151,673 | $ 57,939 |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
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 |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation. |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no 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 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 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 financial statements. 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, the war in Ukraine and the Israel-Hamas War, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and measures to combat persistent inflation and instability in the financial sector have contributed to recent pricing and economic volatility. The financial results of companies in the oil and natural gas industry have been and may continue to be impacted materially as a result of changing market conditions. Such circumstances generally increase 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 each particular circumstance. 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 interests, estimates of third party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties, the fair value determination of assets and liabilities, including those acquired by the Company, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. 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. |
Royalty Income Receivable | Royalty Income Receivable Royalty income receivables consist of receivables for oil and natural gas sales made by the Company’s third-party operators and Diamondback. The operators remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work which is required to be completed by the operator before payments are released. |
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. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” |
Revenue from Contracts with Customers | Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Company’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Company owns a royalty interest sells the Company’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Company collects its percentage royalty based on the revenue generated. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Company’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of the Company’s royalty income contracts. Contract balances Under the Company’s royalty income contracts, it has the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Company’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, 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 royalty income to be received based upon the Company’s interest. The Company records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. 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 royalties related to expected sales volumes and prices for those properties are estimated and recorded. |
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 costs are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2023 and 2022, the Company’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $10.20, $9.86 and $10.04 for the years ended December 31, 2023, 2022 and 2021, respectively. Depletion for oil and natural gas properties was $146.1 million, $121.1 million and $103.0 million 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 interests net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (i) 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, (ii) the cost of properties not being amortized, if any, and (iii) 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. See Note 5— Oil and Natural Gas Interests for additional discussion of the Company’s oil and natural gas properties. 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 at least annually 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 of the operator to drill; remaining lease term with the current operator; 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. |
Debt Issuance Costs | Debt Issuance Costs Other assets include capitalized costs related to the credit facility of $15.5 million and $9.7 million, and accumulated amortization of those costs over the term of the credit facility of $10.0 million and $9.5 million as of December 31, 2023, and 2022, respectively. Long-term debt includes capitalized costs related to t he Company’s 5.375% senior notes due 2027 and 7.375% senior notes due 2031 (collectively, th e “Notes”) . The costs associated with the Notes are being netted against the Notes’ balances and amortized over the term of the Notes using the effective interest method. See Note 6— Debt |
Concentrations | Concentrations The Company is subject to risk resulting from the concentration of the Company’s royalty income in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2023, two purchasers each accounted for more than 10% of royalty income: Vitol Midstream Pipeline LLC (16%) and DK Trading and Supply LLC (15%). For the year ended December 31, 2022, two purchasers each accounted for more than 10% of royalty income: Shell Trading (US) Company (14%) and Vitol Midstream Pipeline LLC (14%). For the year ended December 31, 2021, three purchasers each accounted for more than 10% of royalty income: Trafigura Trading LLC (17%), Shell Trading (US) Company (16%) and Vitol Midstream Pipeline LLC (12%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact the Company’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. |
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. 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, 2022 and 2021, there were no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. See Note 9— Income Taxes for further details. |
Non-controlling Interest | Non-controlling Interest Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and stockholders’ equity, tax effected, will occur. Because these changes in the Company’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Company’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 7— Stockholders' Equity for further discussion of changes in ownership interest. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Recently Adopted Pronouncements There are no recently adopted pronouncements. Accounting Pronouncements Not Yet Adopted 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 fiscal years 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. |
Revenue from Contract with Customer | Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index. |
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. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis on the Company’s consolidated balance sheets, including the Company’s derivative instruments. The fair values of the Company’s 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. These valuations are Level 2 in puts in the fair value hierarchy. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Schedule of Accrued Liabilities | Accrued liabilities consist of the following at December 31, 2023, and 2022: December 31, 2023 2022 (In thousands) Interest payable $ 11,036 $ 3,972 Ad valorem taxes payable 13,299 12,492 Derivatives instruments payable 1,279 1,684 Other 1,407 1,452 Total accrued liabilities $ 27,021 $ 19,600 |
REVENUE FROM CONTRACTS WITH C_2
REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table disaggregates the Company’s total royalty income by product type: Year Ended December 31, 2023 2022 2021 (In thousands) Oil income $ 619,181 $ 667,281 $ 397,513 Natural gas income 30,953 83,149 49,197 Natural gas liquids income 66,976 87,546 54,824 Total royalty income $ 717,110 $ 837,976 $ 501,534 |
Oil and Natural Gas Interests (
Oil and Natural Gas Interests (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Schedule of Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities | Oil and natural gas interests include the following: December 31, 2023 2022 (In thousands) Oil and natural gas interests: Subject to depletion $ 2,859,642 $ 2,167,598 Not subject to depletion 1,769,341 1,297,221 Gross oil and natural gas interests 4,628,983 3,464,819 Accumulated depletion and impairment (866,352) (720,234) Oil and natural gas interests, net 3,762,631 2,744,585 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 3,768,319 $ 2,750,273 Balance of costs not subject to depletion: Incurred in 2023 $ 720,529 Incurred in 2022 33,781 Incurred in 2021 429,991 Prior 585,040 Total not subject to depletion $ 1,769,341 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2023 2022 (In thousands) Oil and natural gas interests: Proved $ 2,859,642 $ 2,167,598 Unproved 1,769,341 1,297,221 Total oil and natural gas interests 4,628,983 3,464,819 Accumulated depletion and impairment (866,352) (720,234) Net oil and natural gas interests capitalized $ 3,762,631 $ 2,744,585 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of Maturities of Long-Term Debt | Long-term debt consisted of the following as of the dates indicated: December 31, 2023 2022 (In thousands) 5.375% senior unsecured notes due 2027 $ 430,350 $ 430,350 7.375% senior unsecured notes due 2031 400,000 — Revolving credit facility 263,000 152,000 Unamortized debt issuance costs (6,903) (1,306) Unamortized discount (3,365) (4,149) Total long-term debt $ 1,083,082 $ 576,895 |
Schedule of Financial Covenants | The credit facility 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 credit facility Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit facility Not less than 1.0 to 1.0 Ratio of secured debt to EBITDAX, as defined in the credit facility Not greater than 2.5 to 1.0 |
Interest Income and Interest Expense Disclosure | 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 thousands) Interest expense $ 48,222 $ 37,539 $ 31,384 Other fees and expenses 836 2,883 2,662 Less: interest income 151 13 2 Interest expense, net $ 48,907 $ 40,409 $ 34,044 |
STOCKHOLDERS_ EQUITY (Tables)
STOCKHOLDERS’ EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Schedule of Change in Ownership Interest | The following table summarizes the changes in stockholders’ equity due to changes in ownership interest during the period: Year Ended December 31, 2023 2022 2021 (In thousands) Net income (loss) attributable to the Company $ 200,088 $ 151,673 $ 57,939 Change in ownership of consolidated subsidiaries (101,632) 58,253 (93,473) Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest $ 98,456 $ 209,926 $ (35,534) |
Dividends Declared | The following table presents information regarding cash distributions and dividends paid during the years ended December 31, 2023, 2022 and 2021 (in thousands, except for per unit amounts): Period Amount per Operating Company Unit Operating Company Distributions to Diamondback Amount per Common Unit Common Unitholders (1) Declaration Date Unitholder Record Date Payment Date Q4 2020 $ 0.14 $ 12,699 $ 0.14 $ 9,162 February 19, 2021 March 4, 2021 March 11, 2021 Q1 2021 $ 0.25 $ 22,678 $ 0.25 $ 16,230 April 27, 2021 May 13, 2021 May 20, 2021 Q2 2021 $ 0.33 $ 29,936 $ 0.33 $ 21,235 July 28, 2021 August 12, 2021 August 19, 2021 Q3 2021 $ 0.38 $ 34,469 $ 0.38 $ 30,118 October 27, 2021 November 11, 2021 November 18, 2021 Q4 2021 $ 0.47 $ 42,634 $ 0.47 $ 36,238 February 16, 2022 March 4, 2022 March 11, 2022 Q1 2022 $ 0.70 $ 63,497 $ 0.67 $ 51,680 April 27, 2022 May 12, 2022 May 19, 2022 Q2 2022 $ 0.87 $ 78,918 $ 0.81 $ 60,626 July 26, 2022 August 16, 2022 August 23, 2022 Q3 2022 $ 0.52 $ 47,170 $ 0.49 $ 36,076 November 3, 2022 November 17, 2022 November 25, 2022 Q4 2022 $ 0.54 $ 48,983 $ 0.49 $ 35,683 February 15, 2023 March 3, 2023 March 10, 2023 Q1 2023 $ 0.42 $ 38,097 $ 0.33 $ 23,797 April 26, 2023 May 11, 2023 May 18, 2023 Q2 2023 $ 0.44 $ 39,912 $ 0.36 $ 25,563 July 25, 2023 August 10, 2023 August 17, 2023 Q3 2023 $ 0.70 $ 63,497 $ 0.57 $ 49,126 November 2, 2023 November 16, 2023 November 24, 2023 (1) Payments made prior to the Conversion include amounts paid to Diamondback for the 731,500 common units then beneficially owned by Diamondback. Payments made after the Conversion include amounts paid to shareholders of Class A Common Stock, including the 7,946,507 shares of Class A Common Stock owned by Diamondback. |
EARNINGS PER COMMON SHARE (Tabl
EARNINGS PER COMMON SHARE (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Schedule of Basic and Diluted Net Income Per Common Share | A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Year Ended December 31, 2023 2022 2021 (In thousands, except per share amounts) Net income (loss) attributable to the period $ 200,088 $ 151,673 $ 57,939 Less: net income (loss) allocated to participating securities (1) 299 365 193 Net income (loss) attributable to common stockholders $ 199,789 $ 151,308 $ 57,746 Weighted average common shares outstanding: Basic weighted average common shares outstanding 74,176 75,612 68,319 Effect of dilutive securities: Potential common shares issuable (2) — 67 72 Diluted weighted average common shares outstanding 74,176 75,679 68,391 Net income (loss) per common stock, basic $ 2.69 $ 2.00 $ 0.85 Net income (loss) per common stock, diluted $ 2.69 $ 2.00 $ 0.85 (1) Unvested restricted stock shares that contain non-forfeitable distribution equivalent rights granted are considered participating securities and therefore are included in the earnings per share calculation pursuant to the two-class method. (2) For the years ended December 31, 2023 and 2022, no significant potential common shares were excluded from the computation of diluted earnings per common share. For the year ended December 31, 2021, 10,160 potential common shares were excluded in the computation of diluted earnings per common share because their inclusion would have been anti-dilutive. |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of the Provision for Income Taxes | The components of the provision for income taxes and effective tax rates for the years ended December 31, 2023, 2022 and 2021 are as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Current income tax provision (benefit): Federal $ 50,414 $ 15,929 $ 1,218 State 2,538 1,074 303 Total current income tax provision (benefit) 52,952 17,003 1,521 Deferred income tax provision (benefit): Federal (6,532) (49,656) — State (468) — — Total deferred income tax provision (benefit) (7,000) (49,656) — Total provision (benefit) from income taxes $ 45,952 $ (32,653) $ 1,521 Effective tax rates 8.4 % (5.2) % 0.6 % |
Schedule of Reconciliation of the Statutory Federal Income Tax | A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Income tax expense (benefit) at the federal statutory rate (21%) $ 114,931 $ 130,694 $ 54,221 Impact of nontaxable noncontrolling interest (63,263) (105,699) (41,735) State income tax expense (benefit), net of federal tax effect 1,657 846 262 Change in valuation allowance (7,281) (58,443) (11,175) Other, net (92) (51) (52) Provision for (benefit from) income taxes $ 45,952 $ (32,653) $ 1,521 |
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: Year Ended December 31, 2023 2022 (In thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 15 $ 70 Investment in the Operating Company 170,164 148,003 Total deferred tax assets 170,179 148,073 Valuation allowance (113,523) (98,417) Net deferred tax assets 56,656 49,656 Net deferred tax assets (liabilities) $ 56,656 $ 49,656 |
DERIVATIVES (Tables)
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 derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. Swaps Collars Puts Settlement Month Settlement Year Type of Contract Bbls/MMBtu Per Day Index Weighted Average Differential Weighted Average Floor Price Weighted Average Ceiling Price Strike Price Deferred Premium OIL Jan. - Mar. 2024 Puts 16,000 WTI Cushing $— $— $— $58.13 $(1.54) Apr. - Jun. 2024 Puts 14,000 WTI Cushing $— $— $— $59.29 $(1.51) Jul. - Dec. 2024 Puts 2,000 WTI Cushing $— $— $— $55.00 $(1.53) Jan. - Jun. 2024 Costless Collar 6,000 WTI Cushing $— $65.00 $95.55 $— $— Jul. - Dec. 2024 Costless Collar 4,000 WTI Cushing $— $55.00 $93.66 $— $— NATURAL GAS Jan. - Dec. 2024 Basis Swaps 30,000 Waha Hub $(1.20) $— $— $— $— Jan. - Dec. 2025 Basis Swaps 40,000 Waha Hub $(0.68) $— $— $— $— |
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 included in the consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Gain (loss) on derivative instruments $ (25,793) $ (18,138) $ (69,409) Net cash receipts (payments) on derivatives (1) $ (13,319) $ (31,319) $ (92,585) (1) The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million. |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets Measured on Recurring and Nonrecurring Basis | The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 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 thousands) Assets: Current: Derivative instruments $ — $ 7,040 $ — $ 7,040 $ (6,682) $ 358 Non-current: Derivative instruments $ — $ 1,269 $ — $ 1,269 $ (1,177) $ 92 Liabilities: Current: Derivative instruments $ — $ 9,643 $ — $ 9,643 $ (6,682) $ 2,961 Non-current: Derivative instruments $ — $ 1,378 $ — $ 1,378 $ (1,177) $ 201 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 thousands) Assets: Current: Derivative instruments $ — $ 13,296 $ — $ 13,296 $ (3,968) $ 9,328 Non-current: Derivative instruments $ — $ 1,911 $ — $ 1,911 $ (1,469) $ 442 Liabilities: Current: Derivative instruments $ — $ 3,968 $ — $ 3,968 $ (3,968) $ — Non-current: Derivative instruments $ — $ 1,476 $ — $ 1,476 $ (1,469) $ 7 |
Schedule of Offsetting Liabilities | The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 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 thousands) Assets: Current: Derivative instruments $ — $ 7,040 $ — $ 7,040 $ (6,682) $ 358 Non-current: Derivative instruments $ — $ 1,269 $ — $ 1,269 $ (1,177) $ 92 Liabilities: Current: Derivative instruments $ — $ 9,643 $ — $ 9,643 $ (6,682) $ 2,961 Non-current: Derivative instruments $ — $ 1,378 $ — $ 1,378 $ (1,177) $ 201 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 thousands) Assets: Current: Derivative instruments $ — $ 13,296 $ — $ 13,296 $ (3,968) $ 9,328 Non-current: Derivative instruments $ — $ 1,911 $ — $ 1,911 $ (1,469) $ 442 Liabilities: Current: Derivative instruments $ — $ 3,968 $ — $ 3,968 $ (3,968) $ — Non-current: Derivative instruments $ — $ 1,476 $ — $ 1,476 $ (1,469) $ 7 |
Schedule of Offsetting Assets | The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 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 thousands) Assets: Current: Derivative instruments $ — $ 7,040 $ — $ 7,040 $ (6,682) $ 358 Non-current: Derivative instruments $ — $ 1,269 $ — $ 1,269 $ (1,177) $ 92 Liabilities: Current: Derivative instruments $ — $ 9,643 $ — $ 9,643 $ (6,682) $ 2,961 Non-current: Derivative instruments $ — $ 1,378 $ — $ 1,378 $ (1,177) $ 201 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 thousands) Assets: Current: Derivative instruments $ — $ 13,296 $ — $ 13,296 $ (3,968) $ 9,328 Non-current: Derivative instruments $ — $ 1,911 $ — $ 1,911 $ (1,469) $ 442 Liabilities: Current: Derivative instruments $ — $ 3,968 $ — $ 3,968 $ (3,968) $ — Non-current: Derivative instruments $ — $ 1,476 $ — $ 1,476 $ (1,469) $ 7 |
Schedule of Fair Value Consolidated Balance Sheets | 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 Value Fair Value Carrying Value Fair Value (In thousands) Debt: Revolving credit facility $ 263,000 $ 263,000 $ 152,000 $ 152,000 5.375% senior notes due 2027 (1) $ 425,949 $ 422,122 $ 424,895 $ 411,634 7.375% senior notes due 2031 (1) $ 394,133 $ 418,408 $ — $ — (1) The carrying value includes associated deferred loan costs and any discount. |
SUPPLEMENTAL INFORMATION ON O_2
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Schedule of Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities | Oil and natural gas interests include the following: December 31, 2023 2022 (In thousands) Oil and natural gas interests: Subject to depletion $ 2,859,642 $ 2,167,598 Not subject to depletion 1,769,341 1,297,221 Gross oil and natural gas interests 4,628,983 3,464,819 Accumulated depletion and impairment (866,352) (720,234) Oil and natural gas interests, net 3,762,631 2,744,585 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 3,768,319 $ 2,750,273 Balance of costs not subject to depletion: Incurred in 2023 $ 720,529 Incurred in 2022 33,781 Incurred in 2021 429,991 Prior 585,040 Total not subject to depletion $ 1,769,341 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2023 2022 (In thousands) Oil and natural gas interests: Proved $ 2,859,642 $ 2,167,598 Unproved 1,769,341 1,297,221 Total oil and natural gas interests 4,628,983 3,464,819 Accumulated depletion and impairment (866,352) (720,234) Net oil and natural gas interests capitalized $ 3,762,631 $ 2,744,585 |
Schedule of Cost Incurred in Oil and Gas Property Acquisition Activities | Costs incurred in oil and natural gas property acquisition activities are as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Acquisition costs: Proved properties $ 402,659 $ 46,307 $ 138,882 Unproved properties 758,342 16,624 479,041 Total $ 1,161,001 $ 62,931 $ 617,923 |
Schedule of Changes in Estimated Proved Reserves | The following table presents changes in estimated proved reserves, which were prepared in accordance with the rules and regulations of the SEC. Oil Natural Gas Natural Gas Liquids Total (MBOE) (1) Proved Developed and Undeveloped Reserves: As of December 31, 2020 57,530 119,450 21,953 99,392 Purchase of reserves in place 5,246 9,549 2,264 9,102 Extensions and discoveries 17,256 39,256 7,182 30,981 Revisions of previous estimates (4,544) 29,788 (1,339) (918) Divestitures (180) (681) (114) (409) Production (6,068) (13,672) (1,913) (10,260) As of December 31, 2021 69,240 183,690 28,033 127,888 Purchase of reserves in place 599 1,186 209 1,006 Extensions and discoveries 15,714 29,177 5,281 25,858 Revisions of previous estimates 1,453 15,248 4,483 8,477 Divestitures (905) (3,469) (564) (2,047) Production (7,097) (15,868) (2,540) (12,282) As of December 31, 2022 79,004 209,964 34,902 148,900 Purchase of reserves in place 10,469 27,011 4,006 18,977 Extensions and discoveries 13,636 34,632 6,150 25,558 Revisions of previous estimates (5,178) 11,101 3,466 138 Production (8,028) (19,130) (3,108) (14,324) As of December 31, 2023 89,903 263,578 45,416 179,249 Proved Developed Reserves: December 31, 2021 49,280 134,485 19,476 91,170 December 31, 2022 54,817 161,119 25,621 107,291 December 31, 2023 69,043 221,462 37,417 143,371 Proved Undeveloped Reserves: December 31, 2021 19,960 49,205 8,557 36,718 December 31, 2022 24,187 48,845 9,281 41,609 December 31, 2023 20,860 42,116 7,999 35,878 (1) Includes total proved reserves of 91,417 MBOE, 81,895 MBOE, 69,060 MBOE and 57,647 MBOE as of December 31, 2023, 2022, 2021 and 2020, respectively, attributable to a non-controlling interest in the Company. The following table includes the changes in PUD reserves for 2023: (MBOE) Beginning proved undeveloped reserves at December 31, 2022 41,609 Undeveloped reserves transferred to developed (13,021) Revisions (5,341) Purchases 2,534 Extensions and discoveries 10,097 Ending proved undeveloped reserves at December 31, 2023 35,878 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows | 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 thousands) Future cash inflows $ 8,493,617 $ 10,072,969 $ 5,763,433 Future production taxes (593,840) (729,256) (416,761) Future income tax expense (934,392) (1,465,160) (572,991) Future net cash flows 6,965,385 7,878,553 4,773,681 10% discount to reflect timing of cash flows (3,778,499) (4,424,457) (2,680,564) Standardized measure of discounted future net cash flows (1) $ 3,186,886 $ 3,454,096 $ 2,093,117 |
Schedule of Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids | The following table 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) $ 77.93 $ 95.04 $ 64.87 Natural gas (per Mcf) $ 1.54 $ 5.74 $ 2.97 Natural gas liquids (per Bbl) $ 23.79 $ 38.95 $ 25.93 |
Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows | 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 thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 3,454,096 $ 2,093,117 $ 1,023,594 Purchase of minerals in place 473,742 30,331 170,205 Divestiture of reserves — (30,076) (4,402) Sales of oil and natural gas, net of production costs (666,709) (781,604) (468,976) Extensions and discoveries 626,854 844,010 615,762 Net changes in prices and production costs (1,405,205) 1,131,202 863,458 Revisions of previous quantity estimates 2,726 309,338 45,788 Net changes in income taxes 212,391 (393,652) (243,186) Accretion of discount 427,998 234,717 103,446 Net changes in timing of production and other 60,993 16,713 (12,572) Standardized measure of discounted future net cash flows at the end of the period $ 3,186,886 $ 3,454,096 $ 2,093,117 |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Details) | 12 Months Ended | ||
Nov. 13, 2023 director shares | Dec. 31, 2023 $ / shares shares | Nov. 12, 2023 | |
Class of Stock [Line Items] | |||
Shares converted (in shares) | 1 | ||
Ownership percentage by parent | 100% | ||
Designated board members (up to) | director | 2 | ||
Minimum | |||
Class of Stock [Line Items] | |||
Voting power to change board designations | 80% | ||
Maximum | |||
Class of Stock [Line Items] | |||
Designated board members (up to) | director | 3 | ||
Common Stock | Minimum | |||
Class of Stock [Line Items] | |||
Ownership percentage by parent | 25% | ||
Class A Shares | |||
Class of Stock [Line Items] | |||
Common stock par value (usd per share) | $ / shares | $ 0.000001 | ||
Shares converted (in shares) | 1 | ||
Class B Shares | |||
Class of Stock [Line Items] | |||
Common stock par value (usd per share) | $ / shares | $ 0.000001 | ||
Shares converted (in shares) | 1 | 1 | |
Ownership percentage by parent | 56% | ||
Diamondback Energy, Inc. | |||
Class of Stock [Line Items] | |||
Shares converted (in shares) | 1 | ||
Diamondback Energy, Inc. | Viper Energy Inc. | |||
Class of Stock [Line Items] | |||
Ownership percentage by parent | 56% |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties, and Debt Issuance Costs (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 USD ($) $ / Boe | Dec. 31, 2022 USD ($) $ / Boe | Dec. 31, 2021 USD ($) $ / Boe | Oct. 19, 2023 | |
Debt Instrument [Line Items] | ||||
Depletion for oil and natural gas properties | $ 146,118 | $ 121,071 | $ 102,987 | |
Estimated future net revenue discounted rate per annum | 10% | |||
Debt issuance costs, net of accumulated amortizations | $ 15,500 | 9,700 | ||
Debit issuance costs, accumulated amortization | $ 10,000 | $ 9,500 | ||
Oil and Gas Properties | ||||
Debt Instrument [Line Items] | ||||
Average depletion rate per barrel equivalent unit of production (usd per BOE) | $ / Boe | 10.20 | 9.86 | 10.04 | |
Depletion for oil and natural gas properties | $ 146,100 | $ 121,100 | $ 103,000 | |
7.375% senior unsecured notes due 2031 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, interest rate, stated percentage | 7.375% | |||
Senior Notes | 5.375% senior unsecured notes due 2027 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, interest rate, stated percentage | 5.375% | |||
Senior Notes | 7.375% senior unsecured notes due 2031 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, interest rate, stated percentage | 7.375% |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Diamondback Energy, Inc. | ||
Related Party Transaction [Line Items] | ||
Lease bonus income | $ 95.8 | |
Royalty Income Receivable | Affiliated Entity | ||
Related Party Transaction [Line Items] | ||
Royalty income receivable | 3.3 | $ 6.3 |
Lease Bonus Income | Affiliated Entity | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amounts of transaction | 107.8 | |
Swallowtail Acquisition Lease Bonus | Affiliated Entity | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amounts of transaction | $ 23.4 |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Accounting Policies [Abstract] | ||
Interest payable | $ 11,036 | $ 3,972 |
Ad valorem taxes payable | 13,299 | 12,492 |
Derivatives instruments payable | 1,279 | 1,684 |
Other | 1,407 | 1,452 |
Total accrued liabilities | $ 27,021 | $ 19,600 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations (Details) - Customer Concentration Risk - Royalty Interest Revenue | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Vitol Midstream Pipeline LLC | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 16% | 14% | 12% |
DK Trading and Supply LLC | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 15% | ||
Shell Trading | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 14% | 16% | |
Trafigura Trading LLC | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 17% |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Accounting Policies [Abstract] | |||
Interest or penalties associated with uncertain tax positions | $ 0 | $ 0 | $ 0 |
REVENUE FROM CONTRACTS WITH C_3
REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | |||
Total royalty income | $ 717,110 | $ 837,976 | $ 501,534 |
Oil income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | 619,181 | 667,281 | 397,513 |
Natural gas income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | 30,953 | 83,149 | 49,197 |
Natural gas liquids income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | $ 66,976 | $ 87,546 | $ 54,824 |
ACQUISITIONS AND DIVESTITURES -
ACQUISITIONS AND DIVESTITURES - Acquisitions (Details) shares in Thousands, $ in Thousands | 12 Months Ended | ||||||
Nov. 01, 2023 USD ($) a shares | Oct. 31, 2023 USD ($) | Mar. 08, 2023 USD ($) a bbl | Oct. 01, 2021 USD ($) a shares | Dec. 31, 2023 USD ($) a | Dec. 31, 2022 USD ($) a | Dec. 31, 2021 USD ($) a | |
Business Acquisition [Line Items] | |||||||
Sale of stock, consideration received on transaction | $ 200,000 | ||||||
GRP Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Equity interest issued (in units) | shares | 9,020 | ||||||
Aggregate purchase price | $ 759,600 | ||||||
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 | ||||||
Drop-Down Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Aggregate purchase price | $ 74,500 | ||||||
Net royalty (acres) | a | 660 | ||||||
Percentage of acreage acquired | 100% | ||||||
Average net royalty interest | 7.20% | ||||||
Daily oil production | bbl | 300 | ||||||
2023 Acquisition Permian Basin | |||||||
Business Acquisition [Line Items] | |||||||
Aggregate purchase price | $ 70,400 | ||||||
Net royalty (acres) | a | 286 | ||||||
2022 Acquisition Permian Basin | |||||||
Business Acquisition [Line Items] | |||||||
Aggregate purchase price | $ 65,800 | ||||||
Net royalty (acres) | a | 375 | ||||||
Swallowtail Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Percentage of acreage acquired | 62% | ||||||
Number of shares issued (in shares) | shares | 15,250 | ||||||
Payments for asset acquisitions | $ 225,300 | ||||||
Payment of contingent consideration | $ 190,000 | ||||||
Swallowtail Acquisition | Northern Midland Basin | |||||||
Business Acquisition [Line Items] | |||||||
Net royalty (acres) | a | 2,313 | ||||||
Other 2021 Acquisitions | |||||||
Business Acquisition [Line Items] | |||||||
Aggregate purchase price | $ 55,100 | ||||||
Net royalty (acres) | a | 392 |
ACQUISITIONS AND DIVESTITURES_2
ACQUISITIONS AND DIVESTITURES - Divestitures (Details) - Discontinued Operations, Disposed of by Sale - Third Party Operated Acreage $ in Millions | 3 Months Ended | ||
Dec. 31, 2022 USD ($) a | Sep. 30, 2022 USD ($) a | Mar. 31, 2022 USD ($) a | |
Eagle Ford Shale | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Area of land | a | 681 | ||
Proceeds from sale of acres | $ | $ 53.7 | ||
Delaware Basin | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Area of land | a | 93 | ||
Proceeds from sale of acres | $ | $ 29.9 | ||
Midland Basin | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Area of land | a | 325 | ||
Proceeds from sale of acres | $ | $ 29.3 |
OIL AND NATURAL GAS INTERESTS_2
OIL AND NATURAL GAS INTERESTS (Details) | 12 Months Ended | |||
Dec. 31, 2023 USD ($) a | Dec. 31, 2022 USD ($) a | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Property, Plant and Equipment [Line Items] | ||||
Subject to depletion | $ 2,859,642,000 | $ 2,167,598,000 | ||
Not subject to depletion | 1,769,341,000 | 1,297,221,000 | ||
Gross oil and natural gas interests | 4,628,983,000 | 3,464,819,000 | ||
Accumulated depletion and impairment | (866,352,000) | (720,234,000) | ||
Oil and natural gas interests, net | 3,762,631,000 | 2,744,585,000 | ||
Land | 5,688,000 | 5,688,000 | ||
Property, net | 3,768,319,000 | 2,750,273,000 | ||
Balance of costs not subject to depletion: | $ 720,529,000 | $ 33,781,000 | $ 429,991,000 | $ 585,040,000 |
Net royalty acres | a | 34,217 | 26,315 | ||
Impairment | $ 0 | $ 0 | $ 0 | |
Minimum | ||||
Property, Plant and Equipment [Line Items] | ||||
Anticipated timing of cost inclusion in amortization calculation | 8 years | |||
Maximum | ||||
Property, Plant and Equipment [Line Items] | ||||
Anticipated timing of cost inclusion in amortization calculation | 10 years |
DEBT - Schedule of Debt (Detail
DEBT - Schedule of Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Oct. 19, 2023 | Dec. 31, 2022 |
Line of Credit Facility [Line Items] | |||
Unamortized debt issuance costs | $ (6,903) | $ (1,306) | |
Unamortized discount | (3,365) | (4,149) | |
Total long-term debt | 1,083,082 | 576,895 | |
Revolving credit facility | Line of Credit | |||
Line of Credit Facility [Line Items] | |||
Long term debt gross | $ 263,000 | 152,000 | |
5.375% senior unsecured notes due 2027 | Senior Notes | |||
Line of Credit Facility [Line Items] | |||
Debt instrument, interest rate, stated percentage | 5.375% | ||
Long term debt gross | $ 430,350 | 430,350 | |
7.375% senior unsecured notes due 2031 | |||
Line of Credit Facility [Line Items] | |||
Debt instrument, interest rate, stated percentage | 7.375% | ||
Long term debt gross | $ 400,000 | $ 0 | |
7.375% senior unsecured notes due 2031 | Senior Notes | |||
Line of Credit Facility [Line Items] | |||
Debt instrument, interest rate, stated percentage | 7.375% |
DEBT - Additional Information (
DEBT - Additional Information (Details) - USD ($) | 12 Months Ended | |||||||
Oct. 19, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Sep. 22, 2023 | May 31, 2023 | May 30, 2023 | Nov. 18, 2022 | |
Line of Credit Facility [Line Items] | ||||||||
Proceeds from senior notes | $ 400,000,000 | $ 0 | $ 0 | |||||
Revolving Credit Facility | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Current borrowing capacity | $ 1,300,000,000 | $ 1,000,000,000 | $ 580,000,000 | |||||
Other commitment | $ 850,000,000 | $ 750,000,000 | $ 500,000,000 | |||||
7.375% senior unsecured notes due 2031 | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Debt instrument, face amount | $ 400,000,000 | |||||||
Debt instrument, interest rate, stated percentage | 7.375% | |||||||
Proceeds from senior notes | $ 394,000,000 | |||||||
Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Maximum borrowing capacity | $ 2,000,000,000 | |||||||
Amount outstanding under credit facility | 263,000,000 | |||||||
Remaining borrowing capacity | $ 587,000,000 | |||||||
Weighted average interest rate | 7.41% | 4.22% | 2.35% | |||||
Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | SOFR | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Basis spread on variable rate | 0.10% | |||||||
Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | Fed Funds Effective Rate | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Basis spread on variable rate | 0.50% | |||||||
Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | 1-month Adjusted Term SOFR | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Basis spread on variable rate | 1% | |||||||
Minimum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Commitment fee on the unused portion of the borrowing base | 0.375% | |||||||
Minimum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | Base Rate | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Debt instrument applicable margin | 1% | |||||||
Minimum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | Adjusted Term SOFR | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Debt instrument applicable margin | 2% | |||||||
Maximum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Commitment fee on the unused portion of the borrowing base | 0.50% | |||||||
Maximum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | Base Rate | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Debt instrument applicable margin | 2% | |||||||
Maximum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | Adjusted Term SOFR | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Debt instrument applicable margin | 3% |
DEBT - Financial Covenants (Det
DEBT - Financial Covenants (Details) - Operating Company 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 facility | 4 |
Ratio of secured debt to EBITDAX, as defined in the credit facility | 2.5 |
Minimum | |
Line of Credit Facility [Line Items] | |
Ratio of current assets to liabilities, as defined in the credit facility | 1 |
DEBT - Interest Expense (Detail
DEBT - Interest Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |||
Interest expense | $ 48,222 | $ 37,539 | $ 31,384 |
Other fees and expenses | 836 | 2,883 | 2,662 |
Less: interest income | 151 | 13 | 2 |
Interest expense, net | $ 48,907 | $ 40,409 | $ 34,044 |
STOCKHOLDERS_ EQUITY - Addition
STOCKHOLDERS’ EQUITY - Additional Information (Details) - USD ($) | 1 Months Ended | 12 Months Ended | |||||
Nov. 13, 2023 | Oct. 31, 2023 | Nov. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Nov. 12, 2023 | |
Class of Stock [Line Items] | |||||||
Ownership percentage by parent | 100% | ||||||
Shares converted (in shares) | 1 | ||||||
Number of shares sold (in shares) | 7,220,000 | ||||||
Sale of stock (usd per share) | $ 27.72 | ||||||
Sale of stock, consideration received on transaction | $ 200,000,000 | ||||||
Intended quarterly dividends | 75% | ||||||
Amount of shares repurchased | $ 95,221,000 | $ 150,593,000 | $ 45,999,000 | ||||
Cash Distribution | |||||||
Class of Stock [Line Items] | |||||||
Cash distributions, distribution period after quarter end | 60 days | ||||||
Common Share Repurchase Program | |||||||
Class of Stock [Line Items] | |||||||
Authorized amount in repurchase program | $ 750,000,000 | ||||||
Amount of shares repurchased | 95,200,000 | $ 150,600,000 | $ 46,000,000 | ||||
Remaining authorized repurchase amount | $ 434,200,000 | ||||||
Diamondback Energy, Inc. | |||||||
Class of Stock [Line Items] | |||||||
Shares converted (in shares) | 1 | ||||||
Diamondback Energy, Inc. | Viper Energy Inc. | |||||||
Class of Stock [Line Items] | |||||||
Ownership percentage by parent | 56% | ||||||
Percentage by noncontrolling owners | 51% | 55% | 54% | ||||
Class A Shares | |||||||
Class of Stock [Line Items] | |||||||
Common stock outstanding (in shares) | 86,144,273 | ||||||
Common stock issued (in shares) | 86,144,273 | ||||||
Shares converted (in shares) | 1 | ||||||
Shares issued (in shares) | 1 | ||||||
Amount of shares repurchased | $ 28,700,000 | $ 37,300,000 | |||||
Repurchased shares (in shares) | 1,000,000 | 1,500,000 | |||||
Class A Shares | Diamondback Energy, Inc. | |||||||
Class of Stock [Line Items] | |||||||
Common stock outstanding (in shares) | 7,946,507 | ||||||
Class B Shares | |||||||
Class of Stock [Line Items] | |||||||
Common stock outstanding (in shares) | 90,709,946 | ||||||
Common stock issued (in shares) | 90,709,946 | ||||||
Ownership percentage by parent | 56% | ||||||
Shares converted (in shares) | 1 | 1 | |||||
Required Dividend Payment | $ 20,000 | ||||||
Class B Shares | Diamondback Energy, Inc. | |||||||
Class of Stock [Line Items] | |||||||
Common stock outstanding (in shares) | 90,709,946 |
STOCKHOLDERS_ EQUITY - Ownershi
STOCKHOLDERS’ EQUITY - Ownership Interest in Subsidiary Changes (Details) - USD ($) $ in Thousands | 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 the Company | $ 200,088 | $ 151,673 | $ 57,939 |
Change in ownership of consolidated subsidiaries, net | 0 | 0 | 0 |
Affiliated Entity | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Net income (loss) attributable to the Company | 200,088 | 151,673 | 57,939 |
Change in ownership of consolidated subsidiaries, net | (101,632) | 58,253 | (93,473) |
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest | $ 98,456 | $ 209,926 | $ (35,534) |
STOCKHOLDERS_ EQUITY - Schedule
STOCKHOLDERS’ EQUITY - Schedule of Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands | Nov. 02, 2023 | Jul. 25, 2023 | Apr. 26, 2023 | Feb. 15, 2023 | Nov. 03, 2022 | Jul. 26, 2022 | Apr. 27, 2022 | Feb. 16, 2022 | Oct. 27, 2021 | Jul. 28, 2021 | Apr. 27, 2021 | Feb. 19, 2021 | Dec. 31, 2023 |
Diamondback Energy, Inc. | |||||||||||||
Class of Stock [Line Items] | |||||||||||||
Limited partners' capital account, units outstanding (in units) | 731,500 | ||||||||||||
Cash Distribution | |||||||||||||
Class of Stock [Line Items] | |||||||||||||
Dividends declared (usd per share) | $ 0.57 | $ 0.36 | $ 0.33 | $ 0.49 | $ 0.49 | $ 0.81 | $ 0.67 | $ 0.47 | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | |
Cash Distribution | Operating Company Share | |||||||||||||
Class of Stock [Line Items] | |||||||||||||
Dividends declared (usd per share) | $ 0.70 | $ 0.44 | $ 0.42 | $ 0.54 | $ 0.52 | $ 0.87 | $ 0.70 | $ 0.47 | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | |
Distribution Amount | $ 63,497 | $ 39,912 | $ 38,097 | $ 48,983 | $ 47,170 | $ 78,918 | $ 63,497 | $ 42,634 | $ 34,469 | $ 29,936 | $ 22,678 | $ 12,699 | |
Cash Distribution | Common Stock | |||||||||||||
Class of Stock [Line Items] | |||||||||||||
Distribution Amount | $ 49,126 | $ 25,563 | $ 23,797 | $ 35,683 | $ 36,076 | $ 60,626 | $ 51,680 | $ 36,238 | $ 30,118 | $ 21,235 | $ 16,230 | $ 9,162 |
EARNINGS PER COMMON SHARE (Deta
EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |||
Net income (loss) attributable to the period | $ 200,088 | $ 151,673 | $ 57,939 |
Less: net income (loss) allocated to participating securities | 299 | 365 | 193 |
Net income (loss) attributable to common stockholders | $ 199,789 | $ 151,308 | $ 57,746 |
Basic weighted average common shares outstanding (in shares) | 74,176,000 | 75,612,000 | 68,319,000 |
Effect of dilutive securities: | |||
Potential common shares issuable (in shares) | 0 | 67,000 | 72,000 |
Diluted weighted average common shares outstanding (in shares) | 74,176,000 | 75,679,000 | 68,391,000 |
Net income (loss) per common stock, basic (usd per share) | $ 2.69 | $ 2 | $ 0.85 |
Net income (loss) per common stock, diluted (usd per share) | $ 2.69 | $ 2 | $ 0.85 |
Antidilutive securities, restricted stock units (in shares) | 0 | 0 | 10,160 |
INCOME TAXES - Components of Pr
INCOME TAXES - Components of Provision for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Current income tax provision (benefit): | |||
Federal | $ 50,414 | $ 15,929 | $ 1,218 |
State | 2,538 | 1,074 | 303 |
Total current income tax provision (benefit) | 52,952 | 17,003 | 1,521 |
Deferred income tax provision (benefit): | |||
Federal | (6,532) | (49,656) | 0 |
State | (468) | 0 | 0 |
Total deferred income tax provision (benefit) | (7,000) | (49,656) | 0 |
Total provision (benefit) from income taxes | $ 45,952 | $ (32,653) | $ 1,521 |
Effective tax rates | 8.40% | (5.20%) | 0.60% |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Statutory Federal Income tax (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense (benefit) at the federal statutory rate (21%) | $ 114,931 | $ 130,694 | $ 54,221 |
Impact of nontaxable noncontrolling interest | (63,263) | (105,699) | (41,735) |
State income tax expense (benefit), net of federal tax effect | 1,657 | 846 | 262 |
Change in valuation allowance | (7,281) | (58,443) | (11,175) |
Other, net | (92) | (51) | (52) |
Total provision (benefit) from income taxes | $ 45,952 | $ (32,653) | $ 1,521 |
INCOME TAXES - Deferred Tax Ass
INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Deferred tax assets: | ||
Net operating loss and capital loss carryforwards | $ 15 | $ 70 |
Investment in the Operating Company | 170,164 | 148,003 |
Total deferred tax assets | 170,179 | 148,073 |
Valuation allowance | (113,523) | (98,417) |
Net deferred tax assets | 56,656 | 49,656 |
Net deferred tax assets (liabilities) | $ 56,656 | $ 49,656 |
INCOME TAXES - Additional Infor
INCOME TAXES - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Loss Carryforwards [Line Items] | |||
Deferred tax assets, net | $ 56,656,000 | $ 49,656,000 | |
Valuation allowance decrease | 7,000,000 | 49,700,000 | |
State income tax expense | 2,538,000 | $ 1,074,000 | $ 303,000 |
State and Local Jurisdiction | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards | $ 0 |
DERIVATIVES - Open Derivative P
DERIVATIVES - Open Derivative Positions (Details) bbl in Thousands | 12 Months Ended |
Dec. 31, 2023 MMBTU $ / bbl $ / MMBTU bbl | |
OIL | WTI Cushing | Puts | 2024 | Jan. - Mar. | |
Derivative [Line Items] | |
Volume (BBls) | bbl | 16 |
Weighted average differential (per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl/MMBtu) | 0 |
Weighted Average Ceiling Price (USD per Bbl/MMBtu) | 0 |
Strike Price (USD per Bbl/MMBtu) | 58.13 |
Deferred premium at a weighted average price (USD per Bbl/MMBtu) | (1.54) |
OIL | WTI Cushing | Puts | 2024 | Apr. - Jun. | |
Derivative [Line Items] | |
Volume (BBls) | bbl | 14 |
Weighted average differential (per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl/MMBtu) | 0 |
Weighted Average Ceiling Price (USD per Bbl/MMBtu) | 0 |
Strike Price (USD per Bbl/MMBtu) | 59.29 |
Deferred premium at a weighted average price (USD per Bbl/MMBtu) | (1.51) |
OIL | WTI Cushing | Puts | 2024 | Jul. - Dec. | |
Derivative [Line Items] | |
Volume (BBls) | bbl | 2 |
Weighted average differential (per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl/MMBtu) | 0 |
Weighted Average Ceiling Price (USD per Bbl/MMBtu) | 0 |
Strike Price (USD per Bbl/MMBtu) | 55 |
Deferred premium at a weighted average price (USD per Bbl/MMBtu) | (1.53) |
OIL | WTI Cushing | Costless Collar | 2024 | Jul. - Dec. | |
Derivative [Line Items] | |
Volume (BBls) | bbl | 4 |
Weighted average differential (per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl/MMBtu) | 55 |
Weighted Average Ceiling Price (USD per Bbl/MMBtu) | 93.66 |
Strike Price (USD per Bbl/MMBtu) | 0 |
Deferred premium at a weighted average price (USD per Bbl/MMBtu) | 0 |
OIL | WTI Cushing | Costless Collar | 2024 | Jan. - Jun. | |
Derivative [Line Items] | |
Volume (BBls) | bbl | 6 |
Weighted average differential (per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl/MMBtu) | 65 |
Weighted Average Ceiling Price (USD per Bbl/MMBtu) | 95.55 |
Strike Price (USD per Bbl/MMBtu) | 0 |
Deferred premium at a weighted average price (USD per Bbl/MMBtu) | 0 |
NATURAL GAS | Waha Hub | Basis Swaps | 2024 | Jan. - Dec. | |
Derivative [Line Items] | |
Weighted average differential (per Bbl) | $ / MMBTU | (1.20) |
Weighted Average Floor Price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Weighted Average Ceiling Price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Strike Price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Deferred premium at a weighted average price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Volume, energy measure (MMBtu) | MMBTU | 30,000 |
NATURAL GAS | Waha Hub | Basis Swaps | 2025 | Jan. - Dec. | |
Derivative [Line Items] | |
Weighted average differential (per Bbl) | $ / MMBTU | (0.68) |
Weighted Average Floor Price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Weighted Average Ceiling Price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Strike Price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Deferred premium at a weighted average price (USD per Bbl/MMBtu) | $ / MMBTU | 0 |
Volume, energy measure (MMBtu) | MMBTU | 40,000 |
DERIVATIVES - Gains and Losses
DERIVATIVES - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Gain (loss) on derivative instruments | $ (25,793) | $ (18,138) | $ (69,409) |
Net cash receipts (payments) on derivatives | $ (13,319) | (31,319) | $ (92,585) |
Cash paid on commodity contracts terminated prior to their contractual maturity | $ 6,600 |
FAIR VALUE MEASUREMENTS - Recur
FAIR VALUE MEASUREMENTS - Recurring Measurements (Details) - Fair Value, Recurring - Derivative instruments - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Current Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | $ 7,040 | $ 13,296 |
Gross Amounts Offset in Balance Sheet | (6,682) | (3,968) |
Net Fair Value Presented in Balance Sheet | 358 | 9,328 |
Noncurrent Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 1,269 | 1,911 |
Gross Amounts Offset in Balance Sheet | (1,177) | (1,469) |
Net Fair Value Presented in Balance Sheet | 92 | 442 |
Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 9,643 | 3,968 |
Gross Amounts Offset in Balance Sheet | (6,682) | (3,968) |
Net Fair Value Presented in Balance Sheet | 2,961 | 0 |
Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 1,378 | 1,476 |
Gross Amounts Offset in Balance Sheet | (1,177) | (1,469) |
Net Fair Value Presented in Balance Sheet | 201 | 7 |
Level 1 | Current Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Level 1 | Noncurrent Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Level 1 | Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 0 | 0 |
Level 1 | Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 0 | 0 |
Level 2 | Current Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 7,040 | 13,296 |
Level 2 | Noncurrent Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 1,269 | 1,911 |
Level 2 | Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 9,643 | 3,968 |
Level 2 | Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 1,378 | 1,476 |
Level 3 | Current Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Level 3 | Noncurrent Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Level 3 | Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 0 | 0 |
Level 3 | Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - Fair
FAIR VALUE MEASUREMENTS - Fair Value of Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Oct. 19, 2023 | Dec. 31, 2022 |
5.375% senior unsecured notes due 2027 | Senior Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, interest rate, stated percentage | 5.375% | ||
7.375% senior unsecured notes due 2031 | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, interest rate, stated percentage | 7.375% | ||
7.375% senior unsecured notes due 2031 | Senior Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, interest rate, stated percentage | 7.375% | ||
Carrying Value | Fair Value, Nonrecurring | Revolving credit facility | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, fair value | $ 263,000 | $ 152,000 | |
Carrying Value | Fair Value, Nonrecurring | 5.375% senior unsecured notes due 2027 | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, fair value | 425,949 | 424,895 | |
Carrying Value | Fair Value, Nonrecurring | 7.375% senior unsecured notes due 2031 | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, fair value | 394,133 | 0 | |
Fair Value | Fair Value, Nonrecurring | Revolving credit facility | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, fair value | 263,000 | 152,000 | |
Fair Value | Fair Value, Nonrecurring | 5.375% senior unsecured notes due 2027 | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, fair value | 422,122 | 411,634 | |
Fair Value | Fair Value, Nonrecurring | 7.375% senior unsecured notes due 2031 | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt instrument, fair value | $ 418,408 | $ 0 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - $ / shares | Feb. 15, 2024 | Nov. 02, 2023 | Jul. 25, 2023 | Apr. 26, 2023 | Feb. 15, 2023 | Nov. 03, 2022 | Jul. 26, 2022 | Apr. 27, 2022 | Feb. 16, 2022 | Oct. 27, 2021 | Jul. 28, 2021 | Apr. 27, 2021 | Feb. 19, 2021 |
Subsequent Event | Base Dividend | Class A Shares | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Dividends payable (usd per share) | $ 0.27 | ||||||||||||
Subsequent Event | Variable Dividend | Class A Shares | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Dividends payable (usd per share) | 0.29 | ||||||||||||
Cash Distribution | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Dividends declared (usd per share) | $ 0.57 | $ 0.36 | $ 0.33 | $ 0.49 | $ 0.49 | $ 0.81 | $ 0.67 | $ 0.47 | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | |
Cash Distribution | Subsequent Event | Class A Shares | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Dividends declared (usd per share) | 0.56 | ||||||||||||
Cash Distribution | Subsequent Event | Operating Company Unit | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Dividends declared (usd per share) | $ 0.69 |
SUPPLEMENTAL INFORMATION ON O_3
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Oil and natural gas interests: | ||
Proved | $ 2,859,642 | $ 2,167,598 |
Unproved | 1,769,341 | 1,297,221 |
Total oil and natural gas interests | 4,628,983 | 3,464,819 |
Accumulated depletion and impairment | (866,352) | (720,234) |
Net oil and natural gas interests capitalized | $ 3,762,631 | $ 2,744,585 |
SUPPLEMENTAL INFORMATION ON O_4
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract] | |||
Proved properties | $ 402,659 | $ 46,307 | $ 138,882 |
Unproved properties | 758,342 | 16,624 | 479,041 |
Total | $ 1,161,001 | $ 62,931 | $ 617,923 |
SUPPLEMENTAL INFORMATION ON O_5
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Changes in Estimated Proved Reserves (Details) MMcf in Thousands, MBbls in Thousands | 12 Months Ended | ||
Dec. 31, 2023 MBoe MBbls MMcf | Dec. 31, 2022 MBoe MMcf MBbls | Dec. 31, 2021 MBoe MMcf MBbls | |
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Total, beginning balance | MBoe | 148,900,000 | 127,888,000 | 99,392,000 |
Purchase of reserves in place | MBoe | 18,977,000 | 1,006,000 | 9,102,000 |
Extensions and discoveries | MBoe | 25,558,000 | 25,858,000 | 30,981,000 |
Revisions of previous estimates | MBoe | 138,000 | 8,477,000 | (918,000) |
Divestitures | MBoe | (2,047,000) | (409,000) | |
Production | MBoe | (14,324,000) | (12,282,000) | (10,260,000) |
Total, ending balance | MBoe | 179,249,000 | 148,900,000 | 127,888,000 |
Proved developed reserves (energy) | MBoe | 143,371,000 | 107,291,000 | 91,170,000 |
Proved undeveloped reserves (energy) | MBoe | 35,878,000 | 41,609,000 | 36,718,000 |
Non-Controlling Interest | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Total, beginning balance | MBoe | 81,895,000 | 69,060,000 | 57,647,000 |
Total, ending balance | MBoe | 91,417,000 | 81,895,000 | 69,060,000 |
Oil | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | 79,004 | 69,240 | 57,530 |
Purchase of reserves in place | 10,469 | 599 | 5,246 |
Extensions and discoveries | 13,636 | 15,714 | 17,256 |
Revisions of previous estimates | (5,178) | 1,453 | (4,544) |
Divestitures | (905) | (180) | |
Production | (8,028) | (7,097) | (6,068) |
End of period | 89,903 | 79,004 | 69,240 |
Proved developed reserves (volume) | 69,043 | 54,817 | 49,280 |
Proved undeveloped reserve (volume) | 20,860 | 24,187 | 19,960 |
Natural Gas | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | MMcf | 209,964 | 183,690 | 119,450 |
Purchase of reserves in place | MMcf | 27,011 | 1,186 | 9,549 |
Extensions and discoveries | MMcf | 34,632 | 29,177 | 39,256 |
Revisions of previous estimates | MMcf | 11,101 | 15,248 | 29,788 |
Divestitures | MMcf | (3,469) | (681) | |
Production | MMcf | (19,130) | (15,868) | (13,672) |
End of period | MMcf | 263,578 | 209,964 | 183,690 |
Proved developed reserves (volume) | MMcf | 221,462 | 161,119 | 134,485 |
Proved undeveloped reserve (volume) | MMcf | 42,116 | 48,845 | 49,205 |
Natural Gas Liquids | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | 34,902 | 28,033 | 21,953 |
Purchase of reserves in place | 4,006 | 209 | 2,264 |
Extensions and discoveries | 6,150 | 5,281 | 7,182 |
Revisions of previous estimates | 3,466 | 4,483 | (1,339) |
Divestitures | (564) | (114) | |
Production | (3,108) | (2,540) | (1,913) |
End of period | 45,416 | 34,902 | 28,033 |
Proved developed reserves (volume) | 37,417 | 25,621 | 19,476 |
Proved undeveloped reserve (volume) | 7,999 | 9,281 | 8,557 |
SUPPLEMENTAL INFORMATION ON O_6
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Additional Information (Details) MMcf in Thousands, MBbls in Thousands | 12 Months Ended | ||
Dec. 31, 2023 MBoe well reserve MBbls MMcf | Dec. 31, 2022 MBoe well MBbls MMcf | Dec. 31, 2021 MBoe well MBbls MMcf | |
Reserve Quantities [Line Items] | |||
Extensions and discoveries | 25,558,000 | 25,858,000 | 30,981,000 |
Oil and gas, development well drilled, net productive, number | well | 904 | 636 | 407 |
New proved undeveloped location | well | 179 | 199 | 336 |
Revisions of previous estimates | 138,000 | 8,477,000 | (918,000) |
MBOE of PUDs downgraded due to positive revisions | 5,688,000 | 15,484,000 | |
MBOE of PUDs downgraded due to price and performance revision | 5,548,000 | 7,007,000 | |
Purchase of reserves in place | 18,977,000 | 1,006,000 | 9,102,000 |
MBOE of PUDs downgraded from non-operated properties | 11,263,000 | ||
MBOE of PUDs downgraded due to changes in the development plan and optimization of the inventory | 10,345,000 | ||
Proved undeveloped reserves (energy) | 35,878,000 | 41,609,000 | 36,718,000 |
Number of horizontal wells developed | well | 529 | ||
Undeveloped reserves transferred to developed | 13,021,000 | ||
Revisions | (5,341,000) | ||
Extensions and discoveries | 10,097,000 | ||
Purchases | 2,534,000 | ||
Planned development period | 5 years | ||
Reserves were classified as proved developed non-producing | reserve | 0 | ||
Oil | |||
Reserve Quantities [Line Items] | |||
Proved undeveloped reserve (volume) | MBbls | 20,860 | 24,187 | 19,960 |
Natural Gas | |||
Reserve Quantities [Line Items] | |||
Proved undeveloped reserve (volume) | MMcf | 42,116 | 48,845 | 49,205 |
Natural Gas Liquids | |||
Reserve Quantities [Line Items] | |||
Proved undeveloped reserve (volume) | MBbls | 7,999 | 9,281 | 8,557 |
Middle Spraberry/Jo Mill | |||
Reserve Quantities [Line Items] | |||
Number of horizontal wells developed | well | 154 | ||
Wolfcamp A | |||
Reserve Quantities [Line Items] | |||
Number of horizontal wells developed | well | 140 | ||
Lower Spraberry | |||
Reserve Quantities [Line Items] | |||
Number of horizontal wells developed | well | 120 | ||
Wolfcamp B | |||
Reserve Quantities [Line Items] | |||
Number of horizontal wells developed | well | 74 | ||
Bone Spring | |||
Reserve Quantities [Line Items] | |||
Number of horizontal wells developed | well | 35 | ||
Dean | |||
Reserve Quantities [Line Items] | |||
Number of horizontal wells developed | well | 6 |
SUPPLEMENTAL INFORMATION ON O_7
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Proved Undeveloped Reserves (Details) | 12 Months Ended |
Dec. 31, 2023 MBoe | |
Proved Undeveloped Reserves (Energy) | |
Beginning proved undeveloped reserves at December 31, 2022 | 41,609,000 |
Undeveloped reserves transferred to developed | (13,021,000) |
Revisions | (5,341,000) |
Purchases | 2,534,000 |
Extensions and discoveries | 10,097,000 |
Ending proved undeveloped reserves at December 31, 2023 | 35,878,000 |
SUPPLEMENTAL INFORMATION ON O_8
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 8,493,617 | $ 10,072,969 | $ 5,763,433 | |
Future production taxes | (593,840) | (729,256) | (416,761) | |
Future income tax expense | (934,392) | (1,465,160) | (572,991) | |
Future net cash flows | 6,965,385 | 7,878,553 | 4,773,681 | |
10% discount to reflect timing of cash flows | (3,778,499) | (4,424,457) | (2,680,564) | |
Standardized measure of discounted future net cash flows | $ 3,186,886 | $ 3,454,096 | $ 2,093,117 | $ 1,023,594 |
Viper Energy Inc. | Diamondback Energy, Inc. | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Percentage by noncontrolling owners | 51% | 55% | 54% |
SUPPLEMENTAL INFORMATION ON O_9
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids (Details) | 12 Months Ended | ||
Dec. 31, 2023 $ / Mcf $ / bbl | Dec. 31, 2022 $ / Mcf $ / bbl | Dec. 31, 2021 $ / bbl $ / Mcf | |
Oil | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Unweighted arithmetic average first-day-of-the-month prices | 77.93 | 95.04 | 64.87 |
Natural Gas | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Unweighted arithmetic average first-day-of-the-month prices | $ / Mcf | 1.54 | 5.74 | 2.97 |
Natural Gas Liquids | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Unweighted arithmetic average first-day-of-the-month prices | 23.79 | 38.95 | 25.93 |
SUPPLEMENTAL INFORMATION ON _10
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 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 | $ 3,454,096 | $ 2,093,117 | $ 1,023,594 |
Purchase of minerals in place | 473,742 | 30,331 | 170,205 |
Divestiture of reserves | 0 | (30,076) | (4,402) |
Sales of oil and natural gas, net of production costs | (666,709) | (781,604) | (468,976) |
Extensions and discoveries | 626,854 | 844,010 | 615,762 |
Net changes in prices and production costs | (1,405,205) | 1,131,202 | 863,458 |
Revisions of previous quantity estimates | 2,726 | 309,338 | 45,788 |
Net changes in income taxes | 212,391 | (393,652) | (243,186) |
Accretion of discount | 427,998 | 234,717 | 103,446 |
Net changes in timing of production and other | 60,993 | 16,713 | (12,572) |
Standardized measure of discounted future net cash flows at the end of the period | $ 3,186,886 | $ 3,454,096 | $ 2,093,117 |