Cover
Cover - USD ($) $ in Billions | 12 Months Ended | |||
Dec. 31, 2022 | Feb. 17, 2023 | Jun. 30, 2022 | Dec. 31, 2021 | |
Entity Information [Line Items] | ||||
Document Type | 10-K | |||
Document Annual Report | true | |||
Document Period End Date | Dec. 31, 2022 | |||
Current Fiscal Year End Date | --12-31 | |||
Document Transition Report | false | |||
Entity File Number | 001-36505 | |||
Entity Registrant Name | Viper Energy Partners LP | |||
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 | Common Units | |||
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 | |||
Entity Shell Company | false | |||
Entity Public Float | $ 2 | |||
Entity Common Units, Units Outstanding | 72,677,022 | |||
Documents Incorporated by Reference | Documents Incorporated By Reference: None | |||
Amendment Flag | false | |||
Document Fiscal Year Focus | 2022 | |||
Document Fiscal Period Focus | FY | |||
Entity Central Index Key | 0001602065 | |||
Class B Units | ||||
Entity Information [Line Items] | ||||
Limited partners' capital account, units outstanding | 90,709,946 | 90,709,946 | 90,709,946 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022 | Dec. 31, 2021 |
Current assets: | ||
Cash and cash equivalents | $ 18,179 | $ 39,448 |
Royalty income receivable (net of allowance for credit losses) | 81,657 | 68,568 |
Royalty income receivable—related party | 6,260 | 2,144 |
Derivative instruments | 9,328 | 0 |
Other current assets | 3,196 | 989 |
Total current assets | 118,620 | 111,149 |
Property: | ||
Oil and natural gas interests, full cost method of accounting ($1,297,221 and $1,640,172 excluded from depletion at December 31, 2022 and December 31, 2021, respectively) | 3,464,819 | 3,513,590 |
Land | 5,688 | 5,688 |
Accumulated depletion and impairment | (720,234) | (599,163) |
Property, net | 2,750,273 | 2,920,115 |
Derivative instruments | 442 | 0 |
Deferred income taxes (net of allowances) | 49,656 | 0 |
Other assets | 1,382 | 2,757 |
Total assets | 2,920,373 | 3,034,021 |
Current liabilities: | ||
Accounts payable | 1,129 | 69 |
Accounts payable—related party | 306 | 0 |
Accrued liabilities | 19,600 | 20,509 |
Derivative instruments | 0 | 3,417 |
Income taxes payable | 911 | 471 |
Total current liabilities | 21,946 | 24,466 |
Long-term debt, net | 576,895 | 776,727 |
Derivative instruments | 7 | 0 |
Total liabilities | 598,848 | 801,193 |
Commitments and contingencies (Note 12) | ||
Unitholders’ equity: | ||
General Partner | 649 | 729 |
Common units (73,229,645 units issued and outstanding as of December 31, 2022 and 78,546,403 units issued and outstanding as of December 31, 2021) | 689,178 | 813,161 |
Class B units (90,709,946 units issued and outstanding December 31, 2022 and December 31, 2021) | 832 | 931 |
Total Viper Energy Partners LP unitholders’ equity | 690,659 | 814,821 |
Non-controlling interest | 1,630,866 | 1,418,007 |
Total equity | 2,321,525 | 2,232,828 |
Total liabilities and unitholders’ equity | $ 2,920,373 | $ 3,034,021 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Feb. 17, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion | $ 1,297,221 | $ 1,640,172 | |
Common Units | |||
Limited partners' capital account, units issued (in shares) | 73,229,645 | 78,546,403 | |
Limited partners' capital account, units outstanding (in shares) | 73,229,645 | 78,546,403 | |
Class B Units | |||
Limited partners' capital account, units issued (in shares) | 90,709,946 | 90,709,946 | |
Limited partners' capital account, units outstanding (in shares) | 90,709,946 | 90,709,946 | 90,709,946 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating income: | |||
Royalty income | $ 837,976,000 | $ 501,534,000 | $ 246,981,000 |
Lease bonus income | 27,791,000 | 2,763,000 | 2,585,000 |
Other operating income | 700,000 | 620,000 | 1,060,000 |
Total operating income | 866,467,000 | 504,917,000 | 250,626,000 |
Costs and expenses: | |||
Production and ad valorem taxes | 56,372,000 | 32,558,000 | 19,844,000 |
Depletion | 121,071,000 | 102,987,000 | 100,501,000 |
Impairment | 0 | 0 | 69,202,000 |
General and administrative expenses | 8,542,000 | 7,800,000 | 8,165,000 |
Total costs and expenses | 185,985,000 | 143,345,000 | 197,712,000 |
Income (loss) from operations | 680,482,000 | 361,572,000 | 52,914,000 |
Other income (expense): | |||
Interest expense, net | (40,409,000) | (34,044,000) | (33,000,000) |
Gain (loss) on derivative instruments, net | (18,138,000) | (69,409,000) | (63,591,000) |
Gain (loss) on revaluation of investment | 0 | 0 | (8,556,000) |
Other income, net | 416,000 | 79,000 | 1,286,000 |
Total other expense, net | (58,131,000) | (103,374,000) | (103,861,000) |
Income (loss) before income taxes | 622,351,000 | 258,198,000 | (50,947,000) |
Provision for (benefit from) income taxes | (32,653,000) | 1,521,000 | 142,466,000 |
Net income (loss) | 655,004,000 | 256,677,000 | (193,413,000) |
Net income (loss) attributable to non-controlling interest | 503,331,000 | 198,738,000 | (1,109,000) |
Net income (loss) attributable to Viper Energy Partners LP | $ 151,673,000 | $ 57,939,000 | $ (192,304,000) |
Net income (loss) attributable to common limited partner units: | |||
Basic (dollars per shares) | $ 2 | $ 0.85 | $ (2.84) |
Diluted (dollars per shares) | $ 2 | $ 0.85 | $ (2.84) |
Weighted average number of common limited partner units outstanding: | |||
Basic (in shares) | 75,612 | 68,319 | 67,686 |
Diluted (in shares) | 75,679 | 68,391 | 67,686 |
Revenue, Product and Service [Extensible Enumeration] | Royalty [Member] | Royalty [Member] | Royalty [Member] |
Statement of Consolidated Unith
Statement of Consolidated Unitholders' Equity - USD ($) shares in Thousands, $ in Thousands | Total | General Partner | Non-Controlling Interest | Common Units Limited Partners | Class B Units Limited Partners |
Beginning balance (in shares) at Dec. 31, 2019 | 67,806 | 90,710 | |||
Beginning balance at Dec. 31, 2019 | $ 2,185,420 | $ 889 | $ 1,254,285 | $ 929,116 | $ 1,130 |
Increase (Decrease) in Partners' Capital | |||||
Unit-based compensation | 1,272 | $ 1,272 | |||
Vesting of restricted stock units (in shares) | 56 | ||||
Distribution equivalent rights payments | (44) | $ (44) | |||
Distributions to public | (45,630) | (45,630) | |||
Distributions to Diamondback | (62,282) | (61,685) | (498) | $ (99) | |
Distributions to General Partner | (80) | (80) | |||
Change in ownership of consolidated subsidiaries, net | 0 | 34,087 | (34,087) | ||
Cash paid for tax withholding on vested common units | (384) | $ (384) | |||
Repurchased units as part of unit buyback (in shares) | (2,045) | ||||
Repurchased units as part of unit buyback | (24,026) | $ (24,026) | |||
Net income (loss) | (193,413) | (1,109) | $ (192,304) | ||
Ending balance (in shares) at Dec. 31, 2020 | 65,817 | 90,710 | |||
Ending balance at Dec. 31, 2020 | 1,860,833 | 809 | 1,225,578 | $ 633,415 | $ 1,031 |
Increase (Decrease) in Partners' Capital | |||||
Unit-based compensation | 1,172 | $ 1,172 | |||
Vesting of restricted stock units (in shares) | 92 | ||||
Common units issued for acquisition (in shares) | 15,250 | ||||
Common units issued for acquisition | 336,872 | $ 336,872 | |||
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) | ||||
Repurchased units as part of unit buyback | (45,999) | $ (45,999) | |||
Net income (loss) | 256,677 | 198,738 | $ 57,939 | ||
Ending balance (in shares) at Dec. 31, 2021 | 78,546 | 90,710 | |||
Ending balance at Dec. 31, 2021 | 2,232,828 | 729 | 1,418,007 | $ 813,161 | $ 931 |
Increase (Decrease) in Partners' Capital | |||||
Unit-based compensation | 1,304 | $ 1,304 | |||
Vesting of restricted stock units (in shares) | 79 | ||||
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) | (5,395) | ||||
Repurchased units as part of unit buyback | (150,593) | $ (150,593) | |||
Net income (loss) | 655,004 | 503,331 | $ 151,673 | ||
Ending balance (in shares) at Dec. 31, 2022 | 73,230 | 90,710 | |||
Ending balance at Dec. 31, 2022 | $ 2,321,525 | $ 649 | $ 1,630,866 | $ 689,178 | $ 832 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 655,004,000 | $ 256,677,000 | $ (193,413,000) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Provision for (benefit from) deferred income taxes | (49,656,000) | 0 | 142,466,000 |
Depletion | 121,071,000 | 102,987,000 | 100,501,000 |
Impairment | 0 | 0 | 69,202,000 |
(Gain) loss on derivative instruments, net | 18,138,000 | 69,409,000 | 63,591,000 |
Net cash receipts (payments) on derivatives | (31,319,000) | (92,585,000) | (36,998,000) |
(Gain) loss on revaluation of investment | 0 | 0 | 8,556,000 |
Other | 5,070,000 | 4,710,000 | 3,589,000 |
Changes in operating assets and liabilities: | |||
Royalty income receivable | (13,089,000) | (36,358,000) | 25,879,000 |
Royalty income receivable—related party | (4,116,000) | (146,000) | 8,578,000 |
Accounts payable and accrued liabilities | 151,000 | 2,744,000 | 5,023,000 |
Accounts payable—related party | 306,000 | 0 | (150,000) |
Other | (1,764,000) | (324,000) | (268,000) |
Net cash provided by (used in) operating activities | 699,796,000 | 307,114,000 | 196,556,000 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas interests | (62,931,000) | (281,176,000) | (65,678,000) |
Proceeds from sale of oil and natural gas interests | 111,702,000 | 0 | 38,594,000 |
Other | (1,200,000) | 0 | 10,801,000 |
Net cash provided by (used in) investing activities | 47,571,000 | (281,176,000) | (16,283,000) |
Cash flows from financing activities: | |||
Proceeds from borrowings under credit facility | 272,000,000 | 330,000,000 | 104,000,000 |
Repayment on credit facility | (424,000,000) | (110,000,000) | (116,500,000) |
Repayment of senior notes | (48,963,000) | 0 | (19,697,000) |
Repurchased units as part of unit buyback | (150,593,000) | (45,999,000) | (24,026,000) |
Distributions to public | (182,835,000) | (75,942,000) | (45,674,000) |
Distributions to Diamondback | (234,103,000) | (100,685,000) | (62,282,000) |
Other | (142,000) | (2,985,000) | (575,000) |
Net cash provided by (used in) financing activities | (768,636,000) | (5,611,000) | (164,754,000) |
Net increase (decrease) in cash and cash equivalents | (21,269,000) | 20,327,000 | 15,519,000 |
Cash, cash equivalents and restricted cash at beginning of period | 39,448,000 | 19,121,000 | 3,602,000 |
Cash, cash equivalents and restricted cash at end of period | 18,179,000 | 39,448,000 | 19,121,000 |
Supplemental disclosure of cash flow information: | |||
Interest paid | 36,868,000 | 30,784,000 | 33,121,000 |
Cash paid (received) for income taxes | 16,990,000 | 1,050,000 | 0 |
Supplemental disclosure of non—cash transactions: | |||
Common units issued for acquisition | $ 0 | $ 336,872,000 | $ 0 |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Presentation | ORGANIZATION AND BASIS OF PRESENTATION Organization Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership 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, 2022, Viper Energy Partners GP LLC (the “General Partner”) held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. (“Diamondback”) beneficially owned approximately 56% of the Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner. 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, unitholders’ equity, results of operations or cash flows. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates Certain amounts included in or affecting the Partnership’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 Partnership reports for assets and liabilities and the Partnership’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 effects of COVID-19, the war in Ukraine and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets continued to contribute to economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts. The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’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 Partnership, 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 Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments. Accounts Receivable Accounts receivable consist of receivables from oil and natural gas sales. The operators remit payment for production directly to the Partnership. 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. Accounts receivable are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Partnership when collection is deemed doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines its allowance utilizing the loss-rate method, which considers a number of factors, including the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2022 and December 31, 2021, the Partnership’s allowance for expected losses was immaterial. Derivative Instruments The Partnership 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 Partnership 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 Partnership 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 Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’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 our royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Partnership 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 Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership 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 Partnership 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 Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2022 and 2021, the Partnership’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 $9.86, $10.04 and $10.34 for the years ended December 31, 2022, 2021 and 2020, respectively. Depletion for oil and natural gas properties was $121.1 million, $103.0 million and $100.5 million for the years ended December 31, 2022, 2021 and 2020, respectively. Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. See Note 5— Oil and Natural Gas Interests for additional discussion of our oil and natural gas properties. Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property at least annually for possible impairment. The Partnership 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 $9.7 million and $9.6 million, and accumulated amortization of those costs over the term of the credit agreement of $9.5 million and $6.8 million as of December 31, 2022, and 2021, respectively. Long-term debt includes insignificant capitalized costs related to t he Partnership’s 5.375% senior notes due 2027 (the “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 During the year ended December 31, 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $23.4 million of lease bonus income primarily related to lease ratification and certain leases acquired in the Swallowtail Acquisition. During the year ended December 31, 2021, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $1.3 million of lease bonus income related to two new leases. 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, 2022, and 2021: December 31, 2022 2021 (In thousands) Interest payable $ 3,972 $ 4,430 Ad valorem taxes payable 12,492 6,201 Derivatives instruments payable 1,684 8,879 Other 1,452 999 Total accrued liabilities $ 19,600 $ 20,509 Concentrations The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty income in producing oil and natural gas properties and receivables with several significant purchasers. 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%). For the year ended December 31, 2020, four purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (23%), Vitol Midstream Pipeline LLC (14%), Shell Trading (US) Company (13%) and Concho Resources (11%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Income Taxes The Partnership 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 Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2022, 2021 and 2020, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’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 common unitholder equity, tax effected, will occur. Because these changes in the Partnership’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 Partnership’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— Unitholders' Equity and Distributions for further discussion of changes in ownership interest. Recent Accounting Pronouncements Recently Adopted Pronouncements In December 2022, the FASB issued ASU 2022-06, "Reference Rate Reform (Topic 848) – Deferral of the Sunset Date of Topic 848.” This update extended the use of the optional expedient through December 31, 2024. The Company adopted this update effective December 31, 2022. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted |
REVENUE FROM CONTRACTS WITH CUS
REVENUE FROM CONTRACTS WITH CUSTOMERS | 12 Months Ended |
Dec. 31, 2022 | |
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 Partnership 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 Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. For the years ended December 31, 2022, 2021 and 2020, any revenues recognized in the current reporting period for performance obligations satisfied in prior reporting periods was not material. The following table disaggregates the Partnership’s total royalty income by product type: Year Ended December 31, 2022 2021 2020 (In thousands) Oil income $ 667,281 $ 397,513 $ 217,859 Natural gas income 83,149 49,197 9,024 Natural gas liquids income 87,546 54,824 20,098 Total royalty income $ 837,976 $ 501,534 $ 246,981 |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended |
Dec. 31, 2022 | |
Business Combinations And Divestitures [Abstract] | |
ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES 2022 Activity Acquisitions During the year ended December 31, 2022 , in individually insignificant transactions, the Partnership 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 $65.9 million, including certain customary closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. Divestitures In the first quarter of 2022, the Partnership 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. In the third quarter of 2022, the Partnership 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 fourth quarter of 2022, the Partnership 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 $53.8 million, including certain customary closing adjustments. 2021 Acquisitions Swallowtail Acquisition On October 1, 2021 , the Partnership 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 units 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 of $190.0 million borrowings under the Operating Company’s revolving credit facility. Other 2021 Acquisitions Additionally during the year ended December 31, 2021, the Partnership acquired, from unrelated third party sellers, mineral and royalty interests representing 1,277 gross (392 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $55.1 million, after post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. 2020 Acquisitions During the year ended December 31, 2020, the Partnership acquired, from unrelated third party sellers, mineral and royalty interests representing 4,948 gross (417 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $64.2 million, after post-closing adjustments. The Partnership 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, 2022 | |
Extractive Industries [Abstract] | |
OIL AND NATURAL GAS INTERESTS | OIL AND NATURAL GAS INTERESTS Oil and natural gas interests include the following: December 31, 2022 2021 (In thousands) Oil and natural gas interests: Subject to depletion $ 2,167,598 $ 1,873,418 Not subject to depletion 1,297,221 1,640,172 Gross oil and natural gas interests 3,464,819 3,513,590 Accumulated depletion and impairment (720,234) (599,163) Oil and natural gas interests, net 2,744,585 2,914,427 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 2,750,273 $ 2,920,115 Balance of costs not subject to depletion: Incurred in 2022 $ 37,456 Incurred in 2021 478,747 Incurred in 2020 55,041 Prior 725,977 Total not subject to depletion $ 1,297,221 As of December 31, 2022 and December 31, 2021, the Partnership had mineral and royalty interests representing 26,315 and 27,027 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 Partnership’s unevaluated costs into the amortization base is expected to be completed within eight Based on the results of the quarterly ceiling tests, the Partnership was not required to record an impairment on our proved oil and natural gas interests for the years ended December 31, 2022 and 2021, respectively. The Partnership recorded an impairment expense of $69.2 million as a result of the decline in commodity prices for the year ended December 31, 2020. In addition to commodity prices, the Partnership’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 Partnership will have write-downs in subsequent quarters, which may be material. |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
DEBT | DEBT Long-term debt consisted of the following as of the dates indicated: December 31, 2022 2021 (In thousands) 5.375% senior unsecured notes due 2027 $ 430,350 $ 479,938 Revolving credit facility 152,000 304,000 Unamortized debt issuance costs (1,306) (1,757) Unamortized discount (4,149) (5,454) Total long-term debt $ 576,895 $ 776,727 Repurchases of Notes During the year ended December 31, 2022, the Partnership repurchased an aggregate $49.6 million principal amount of the outstanding Notes for total cash consideration of $49.0 million, which resulted in an immaterial loss on extinguishment of debt after including accrued interest and the write-off of related unamortized costs. The Partnership funded the debt repurchases through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. The Operating Company’s Revolving Credit Facility The Operating Company, as borrower, and the Partnership, as parent guarantor, maintain a credit agreement, as amended, which provides for a maximum credit amount of $2.0 billion and a borrowing base of $580.0 million. As of December 31, 2022, the Operating Company had elected a commitment amount of $500.0 million, with $152.0 million of outstanding borrowings and $348.0 million available for future borrowings under the Operating Company’s revolving cred it facility. For the years ended December 31, 2022, 2021 and 2020, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was 4.22% , 2.35%, and 2.20% , respectively. On November 18, 2022, the Operating Company entered into the ninth amendment to the existing credit agreement, which, among other things, (i) maintained the maximum amount of the revolving credit facility at $2.0 billion, (ii) reaffirmed the borrowing base of $580.0 million based on the Operating Company’s oil and natural gas reserves and other factors, (iii) maintained the Operating Company’s ability to elect a commitment amount that is less than its borrowing base as determined by the lenders, and (iv) replaced the London interbank offered rate benchmark with the secured overnight financing rate (“SOFR”). The outstanding borrowings under the credit agreement 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 agreement is secured by substantially all the assets of the Partnership and the Operating Company. The Partnership applied the optional expedient in ASU 2020-04, “Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting” for this contract modification, which did not have an impact on its financial position, results of operations or liquidity. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, excess cash and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 Ratio of secured debt to EBITDAX, as defined in the credit agreement Not greater than 2.5 to 1.0 As of December 31, 2022, the Operating Company was in compliance with all financial maintenance covenants under its credit agreement. |
UNITHOLDERS_ EQUITY AND DISTRIB
UNITHOLDERS’ EQUITY AND DISTRIBUTIONS | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
UNITHOLDERS’ EQUITY AND DISTRIBUTIONS | UNITHOLDERS’ EQUITY AND DISTRIBUTIONS The Partnership has General Partner and limited partner units. At December 31, 2022, the Partnership had a total of 73,229,645 common units issued and outstanding and 90,709,946 Class B units issued and outstanding, of which 731,500 common units and 90,709,946 Class B units were beneficially owned by Diamondback, representing approximately 56% of the Partnership’s total units outstanding. Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 55% non- controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit). Common Unit Repurchase Program The board of directors of the Partnership’s General P artner has approved a common unit repurchase program to acquire up to $750.0 million of the Partnership’s outstanding common units over an indefinite period of time. The Partnership intends to purchase common units 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 Partnership’s General Partner at any time. During the years ended December 31, 2022, 2021 and 2020, the Partnership repurchased approximately $150.6 million, $46.0 million, and $24.0 million of common units under the repurchase program, respectively. As of December 31, 2022, $529.4 million remains available for use under the repurchase program. 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 Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on the Partnership’s units. These changes in ownership percentage and the disproportionate allocation of net income (loss) to Diamondback discussed below result in adjustments to non-controlling interest and common unitholder equity, tax effected, but do not impact earnings. The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the period: Year Ended December 31, 2022 2021 2020 (In thousands) Net income (loss) attributable to the Partnership $ 151,673 $ 57,939 $ (192,304) Change in ownership of consolidated subsidiaries 58,253 (93,473) (34,087) Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest $ 209,926 $ (35,534) $ (226,391) Cash Distributions The board of directors of the General Partner has established a distribution policy, as amended, whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to its unitholders (including Diamondback and the Partnership). The Partnership in turn distributes all or a portion of the available cash it receives from the Operating Company to its common unitholders. The Partnership’s available cash and the available cash of the Operating Company for each quarter is determined by the board of directors of the General Partner following the end of such quarter. The cash available for distribution by the Operating Company, a non-GAAP measure, generally equals the Partnership’s consolidated Adjusted EBITDA 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 board of directors of the General Partner deems necessary or appropriate, lease bonus income, distribution equivalent rights payments and preferred distributions, if any. The Partnership’s cash available for distribution for each quarter generally equals the Partnership’s proportional share of the cash distributed by the Operating Company for the quarter, less cash needed by the Partnership for the payment of income taxes, if any, and the preferred distribution. Further, i n July 2022, the board of directors of the General Partner approved a distribution policy, effective with the Partnership’s distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. The board of directors updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculation of the Partnership’s and the Operating Company’s available cash. The percentage of cash available for distribution pursuant to the distribution policy discussed above may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis. The following table presents information regarding cash distributions paid during the years ended December 31, 2022, 2021 and 2020 (in thousands, except for per share 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 2019 $ 0.45 $ 40,819 $ 0.45 $ 30,543 February 7, 2020 February 21, 2020 February 28, 2020 Q1 2020 $ 0.10 $ 9,074 $ 0.10 $ 6,790 April 30, 2020 May 14, 2020 May 21, 2020 Q2 2020 $ 0.03 $ 2,720 $ 0.03 $ 2,034 July 29, 2020 August 13, 2020 August 20, 2020 Q3 2020 $ 0.10 $ 9,072 $ 0.10 $ 6,805 October 28, 2020 November 12, 2020 November 19, 2020 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 (1) Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback and distribution equivalent rights payments. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Allocation of Net Income The Partnership, as 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 the reporting periods. |
EARNINGS PER COMMON UNIT
EARNINGS PER COMMON UNIT | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
EARNINGS PER COMMON UNIT | EARNINGS PER COMMON UNIT The net income (loss) per common unit on the consolidated statements of operations is based on the net income (loss) attributable to the Partnership’s common units for the years ended December 31, 2022, 2021 and 2020. The Partnership’s net income (loss) is allocated wholly to the common units, as the General Partner does not have an economic interest. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 7— Unitholders' Equity and Distributions . Basic and diluted earnings per common unit is calculated using the two-class method. The two class method is an earnings allocation proportional to the respective ownership among holders of common units and participating securities. Basic net income (loss) per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the LTIP. A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below: Year Ended December 31, 2022 2021 2020 (In thousands, except per unit amounts) Net income (loss) attributable to the period $ 151,673 $ 57,939 $ (192,304) Less: net income (loss) allocated to participating securities (1) 365 193 44 Net income (loss) attributable to common unitholders $ 151,308 $ 57,746 $ (192,348) Weighted average common units outstanding: Basic weighted average common units outstanding 75,612 68,319 67,686 Effect of dilutive securities: Potential common units issuable (2) 67 72 — Diluted weighted average common units outstanding 75,679 68,391 67,686 Net income (loss) per common unit, basic $ 2.00 $ 0.85 $ (2.84) Net income (loss) per common unit, diluted $ 2.00 $ 0.85 $ (2.84) (1) Restricted stock units with non-forfeitable distribution equivalent rights granted to employees are considered participating securities. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The Partnership’s total income tax benefit and expense for the years ended December 31, 2022 and 2021, 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 a reduction to its valuation allowance in 2022 and maintaining a valuation allowance on the Partnership’s deferred tax assets in 2021. For the year ended December 31, 2020, total income tax expense differed from amounts computed by applying the United States federal statutory rate to pre-tax loss for the period primarily due to net loss attributable to the non-controlling interest and the impact of recording a valuation allowance on the Partnership’s deferred tax assets. The components of the provision for income taxes and effective tax rates for the years ended December 31, 2022, 2021 and 2020 are as follows: Year Ended December 31, 2022 2021 2020 (In thousands) Current income tax provision (benefit): Federal $ 15,929 $ 1,218 $ — State 1,074 303 — Total current income tax provision (benefit) 17,003 1,521 — Deferred income tax provision (benefit): Federal (49,656) — 142,466 State — — — Total deferred income tax provision (benefit) (49,656) — 142,466 Total provision (benefit) from income taxes $ (32,653) $ 1,521 $ 142,466 Effective tax rates (5.2) % 0.6 % (279.6) % A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2022 2021 2020 (In thousands) Income tax expense (benefit) at the federal statutory rate (21%) $ 130,694 $ 54,221 $ (10,699) Impact of nontaxable noncontrolling interest (105,699) (41,735) 233 State income tax expense (benefit), net of federal tax effect 846 262 — Change in valuation allowance (58,443) (11,175) 152,898 Other, net (51) (52) 34 Provision for (benefit from) income taxes $ (32,653) $ 1,521 $ 142,466 The components of the Partnership’s deferred tax assets and liabilities as of December 31, 2022 and 2021 are as follows: Year Ended December 31, 2022 2021 (In thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 70 $ 6,014 Investment in the Operating Company 148,003 163,065 Total deferred tax assets 148,073 169,079 Valuation allowance (98,417) (169,079) Net deferred tax assets 49,656 — Net deferred tax assets (liabilities) $ 49,656 $ — At December 31, 2022, the Partnership has net deferred tax assets of approximately $49.7 million, including federal capital loss carryforwards expiring in 2026-2027 of approximately $0.1 million, and immaterial state operating loss carryforwards. Deferred taxes are provided on the difference between the Partnership’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in the Operating Company. During the year ended December 31, 2022, the Partnership recognized discrete income tax benefit of $49.7 million 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. At December 31, 2021, the Partnership had a full valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets. The Partnership principally operates in the state of Texas. For the years ended December 31, 2022 and 2021, the Partnership recognized $1.1 million and $0.3 million, respectively, in state income tax expense primarily for its share of Texas margin tax attributable to the Partnership’s results which are included in a combined tax return filed by Diamondback. At December 31, 2022, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements. The Partnership’s 2018 through 2022 tax years remain open to examination by tax authorities. The CHIPS and Science Act of 2022 (“CHIPS”) was enacted on August 9, 2022, and the Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, which imposes a 15% corporate alternative minimum tax on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock/unit repurchases for tax years beginning after December 31, 2022, and included several other provisions applicable to U.S. income taxes for corporations. The Partnership considered the impact of this legislation in the period of enactment and concluded there was not a material impact to the Partnership’s current or deferred income tax balances. |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVES | DERIVATIVES During 2022, the Partnership 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, 2022, the Partnership has puts and fixed price basis swap contracts outstanding. The Partnership’s put contracts for oil are based upon reported settlement prices based on New York Mercantile Exchange West Texas Intermediate (“Cushing WTI”). The Partnership’s fixed price basis swaps for oil are for the spread between the Cushing WTI crude oil price and the Midland WTI crude oil price. The Partnership’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 Cushing WTI oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership 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 Partnership, which creates credit risk. The Partnership’s counterparties are all participants in the amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Partnership is not required to post any collateral. The Partnership’s counterparties have been determined to have an acceptable credit risk; therefore, the Partnership does not require collateral from its counterparties. As of December 31, 2022, the Partnership 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/Mcf Per Day Index Weighted Average Differential Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Strike Price OIL Jan. - Mar. 2023 Puts (1) 12,000 WTI Cushing $— $— $— $— $54.50 Apr. - Jun. 2023 Puts (2) 8,000 WTI Cushing $— $— $— $— $55.00 Jan. - Dec. 2023 Basis Swaps 4,000 Argus WTI Midland $1.05 $— $— $— $— NATURAL GAS Jan. - Dec. 2023 Basis Swaps 30,000 Waha Hub $(1.33) $— $— $— $— Jan. - Dec. 2024 Basis Swaps 20,000 Waha Hub $(1.23) $— $— $— $— (1) Includes a deferred premium at a weighted average price of $1.82/Bbl. (2) Includes a deferred premium at a weighted average price of $1.79/Bbl. Balance Sheet Offsetting of Derivative Assets and Liabilities The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, 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, 2022 2021 2020 (In thousands) Gain (loss) on derivative instruments $ (18,138) $ (69,409) $ (63,591) Net cash receipts (payments) on derivatives (1) $ (31,319) $ (92,585) $ (36,998) |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2022 | |
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 Partnership’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 Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis, including the Partnership’s derivative instruments. The fair values of the Partnership’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. 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 Partnership’s consolidated balance sheets as of December 31, 2022 and December 31, 2021. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. 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 As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 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, 2022 December 31, 2021 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Debt: Revolving credit facility $ 152,000 $ 152,000 $ 304,000 $ 304,000 5.375% senior notes due 2027 (1) $ 424,895 $ 411,634 $ 472,727 $ 498,992 (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 Partnership 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, 2022 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 our 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 Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current assets, other assets, accounts payable and accrued liabilities. 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, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIESThe Partnership 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 Partnership, cannot be predicted with certainty, the Partnership’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership’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 Partnership’s assessment. The Partnership 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, 2022 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENTS Cash Distribution On February 15, 2023, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2022 of $0.49 per common unit, payable on March 10, 2023, to unitholders of record at the close of business on March 3, 2023. The distribution consists of a base quarterly distribution of $0.25 per common unit and a variable quarterly distribution of $0.24 per common unit. |
SUPPLEMENTAL INFORMATION ON OIL
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil and Natural Gas Operations (Unaudited) | SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) The Partnership’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, 2022 2021 (In thousands) Oil and natural gas interests: Proved $ 2,167,598 $ 1,873,418 Unproved 1,297,221 1,640,172 Total oil and natural gas interests 3,464,819 3,513,590 Accumulated depletion and impairment (720,234) (599,163) Net oil and natural gas interests capitalized $ 2,744,585 $ 2,914,427 Costs incurred in oil and natural gas activities Costs incurred in oil and natural gas property acquisition activities are as follows: December 31, 2022 2021 2020 (In thousands) Acquisition costs: Proved properties $ 46,307 $ 138,882 $ 9,509 Unproved properties 16,624 479,041 56,169 Total $ 62,931 $ 617,923 $ 65,678 Results of Operations from Oil and Natural Gas Producing Activities Substantially all of the Partnership’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, 2022 and prepared by Ryder Scott as of December 31, 2021 and 2020. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The changes in estimated proved reserves are as follows: Oil Natural Gas Natural Gas Liquids Total (MBOE) (In thousands) Proved Developed and Undeveloped Reserves: As of December 31, 2019 54,420 95,774 18,564 88,946 Purchase of reserves in place 491 507 113 689 Extensions and discoveries 15,415 23,982 4,424 23,836 Revisions of previous estimates (6,685) 11,043 763 (4,082) Divestitures (155) (370) (63) (280) Production (5,956) (11,486) (1,848) (9,718) 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 Proved Developed Reserves: December 31, 2020 40,220 93,617 16,724 72,547 December 31, 2021 49,280 134,485 19,476 91,170 December 31, 2022 54,817 161,119 25,621 107,291 Proved Undeveloped Reserves: December 31, 2020 17,310 25,833 5,229 26,845 December 31, 2021 19,960 49,205 8,557 36,718 December 31, 2022 24,187 48,845 9,281 41,609 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, 2022, the Partnership’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 Partnership’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 Partnership’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 Partnership’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. During the year ended December 31, 2020, the Partnership’s extensions and discoveries of 23,836 MBOE resulted primarily from the drilling of 652 new wells and from 299 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 4,082 MBOE were due to negative price revisions and PUD downgrades. 114 MBOE of PUDs were downgraded from non-operated properties and 804 MBOE of PUDs were downgraded from Diamondback-operated properties, with the Diamondback-operated downgrades due to changes in the development plan and optimization of the inventory. The purchase of reserves in place of 689 MBOE were due to multiple acquisitions of certain mineral and royalty interests. Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. 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 Partnership. 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 Partnership’s proved oil and natural gas reserves as of December 31, 2022, 2021 and 2020: December 31, 2022 2021 2020 (In thousands) Future cash inflows $ 10,072,969 $ 5,763,433 $ 2,460,052 Future production taxes (729,256) (416,761) (181,067) Future income tax expense (1,465,160) (572,991) (22,993) Future net cash flows 7,878,553 4,773,681 2,255,992 10% discount to reflect timing of cash flows (4,424,457) (2,680,564) (1,232,398) Standardized measure of discounted future net cash flows $ 3,454,096 $ 2,093,117 $ 1,023,594 The following table presents the weighted average first-day-of–the-month prices for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows: December 31, 2022 2021 2020 Oil (per Bbl) $ 95.04 $ 64.87 $ 37.61 Natural gas (per Mcf) $ 5.74 $ 2.97 $ 0.34 Natural gas liquids (per Bbl) $ 38.95 $ 25.93 $ 11.65 Principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves are as follows: December 31, 2022 2021 2020 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 2,093,117 $ 1,023,594 $ 1,318,388 Purchase of minerals in place 30,331 170,205 10,781 Divestiture of reserves (30,076) (4,402) (3,481) Sales of oil and natural gas, net of production costs (781,604) (468,976) (227,137) Extensions and discoveries 844,010 615,762 280,486 Net changes in prices and production costs 1,131,202 863,458 (465,582) Revisions of previous quantity estimates 309,338 45,788 (87,614) Net changes in income taxes (393,652) (243,186) 59,754 Accretion of discount 234,717 103,446 138,901 Net changes in timing of production and other 16,713 (12,572) (902) Standardized measure of discounted future net cash flows at the end of the period $ 3,454,096 $ 2,093,117 $ 1,023,594 |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
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, unitholders’ equity, results of operations or cash flows. |
Use of Estimates | Use of Estimates Certain amounts included in or affecting the Partnership’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 Partnership reports for assets and liabilities and the Partnership’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 effects of COVID-19, the war in Ukraine and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets continued to contribute to economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts. The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’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 Partnership, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances. |
Cash and Cash Equivalents | Cash and Cash EquivalentsCash 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 Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments. |
Accounts Receivable | Accounts Receivable Accounts receivable consist of receivables from oil and natural gas sales. The operators remit payment for production directly to the Partnership. 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 Partnership 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 Partnership 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 Partnership 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 Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’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 our royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Partnership 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 Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership 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 Partnership 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 Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2022 and 2021, the Partnership’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 $9.86, $10.04 and $10.34 for the years ended December 31, 2022, 2021 and 2020, respectively. Depletion for oil and natural gas properties was $121.1 million, $103.0 million and $100.5 million for the years ended December 31, 2022, 2021 and 2020, respectively. Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. See Note 5— Oil and Natural Gas Interests for additional discussion of our oil and natural gas properties. Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property at least annually for possible impairment. The Partnership 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 $9.7 million and $9.6 million, and accumulated amortization of those costs over the term of the credit agreement of $9.5 million and $6.8 million as of December 31, 2022, and 2021, respectively. Long-term debt includes insignificant capitalized costs related to t he Partnership’s 5.375% senior notes due 2027 (the “Notes”) |
Concentrations | Concentrations The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty income in producing oil and natural gas properties and receivables with several significant purchasers. 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%). For the year ended December 31, 2020, four purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (23%), Vitol Midstream Pipeline LLC (14%), Shell Trading (US) Company (13%) and Concho Resources (11%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. |
Income Taxes | Income Taxes The Partnership 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. |
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 common unitholder equity, tax effected, will occur. Because these changes in the Partnership’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 Partnership’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— Unitholders' Equity and Distributions for further discussion of changes in ownership interest. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Recently Adopted Pronouncements In December 2022, the FASB issued ASU 2022-06, "Reference Rate Reform (Topic 848) – Deferral of the Sunset Date of Topic 848.” This update extended the use of the optional expedient through December 31, 2024. The Company adopted this update effective December 31, 2022. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted |
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 Partnership 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 Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’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 Partnership’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 Partnership 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 |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Schedule of Accrued Liabilities | Accrued liabilities consist of the following at December 31, 2022, and 2021: December 31, 2022 2021 (In thousands) Interest payable $ 3,972 $ 4,430 Ad valorem taxes payable 12,492 6,201 Derivatives instruments payable 1,684 8,879 Other 1,452 999 Total accrued liabilities $ 19,600 $ 20,509 |
REVENUE FROM CONTRACTS WITH C_2
REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table disaggregates the Partnership’s total royalty income by product type: Year Ended December 31, 2022 2021 2020 (In thousands) Oil income $ 667,281 $ 397,513 $ 217,859 Natural gas income 83,149 49,197 9,024 Natural gas liquids income 87,546 54,824 20,098 Total royalty income $ 837,976 $ 501,534 $ 246,981 |
Oil and Natural Gas Interests (
Oil and Natural Gas Interests (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022 2021 (In thousands) Oil and natural gas interests: Subject to depletion $ 2,167,598 $ 1,873,418 Not subject to depletion 1,297,221 1,640,172 Gross oil and natural gas interests 3,464,819 3,513,590 Accumulated depletion and impairment (720,234) (599,163) Oil and natural gas interests, net 2,744,585 2,914,427 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 2,750,273 $ 2,920,115 Balance of costs not subject to depletion: Incurred in 2022 $ 37,456 Incurred in 2021 478,747 Incurred in 2020 55,041 Prior 725,977 Total not subject to depletion $ 1,297,221 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2022 2021 (In thousands) Oil and natural gas interests: Proved $ 2,167,598 $ 1,873,418 Unproved 1,297,221 1,640,172 Total oil and natural gas interests 3,464,819 3,513,590 Accumulated depletion and impairment (720,234) (599,163) Net oil and natural gas interests capitalized $ 2,744,585 $ 2,914,427 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of Maturities of Long-Term Debt | Long-term debt consisted of the following as of the dates indicated: December 31, 2022 2021 (In thousands) 5.375% senior unsecured notes due 2027 $ 430,350 $ 479,938 Revolving credit facility 152,000 304,000 Unamortized debt issuance costs (1,306) (1,757) Unamortized discount (4,149) (5,454) Total long-term debt $ 576,895 $ 776,727 |
Schedule of Financial Covenants | The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, excess cash and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 Ratio of secured debt to EBITDAX, as defined in the credit agreement Not greater than 2.5 to 1.0 |
UNITHOLDERS_ EQUITY AND DISTR_2
UNITHOLDERS’ EQUITY AND DISTRIBUTIONS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Change in Ownership Interest | The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the period: Year Ended December 31, 2022 2021 2020 (In thousands) Net income (loss) attributable to the Partnership $ 151,673 $ 57,939 $ (192,304) Change in ownership of consolidated subsidiaries 58,253 (93,473) (34,087) Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest $ 209,926 $ (35,534) $ (226,391) |
Distributions Made to Limited Partner, by Distribution | The following table presents information regarding cash distributions paid during the years ended December 31, 2022, 2021 and 2020 (in thousands, except for per share 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 2019 $ 0.45 $ 40,819 $ 0.45 $ 30,543 February 7, 2020 February 21, 2020 February 28, 2020 Q1 2020 $ 0.10 $ 9,074 $ 0.10 $ 6,790 April 30, 2020 May 14, 2020 May 21, 2020 Q2 2020 $ 0.03 $ 2,720 $ 0.03 $ 2,034 July 29, 2020 August 13, 2020 August 20, 2020 Q3 2020 $ 0.10 $ 9,072 $ 0.10 $ 6,805 October 28, 2020 November 12, 2020 November 19, 2020 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 (1) Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback and distribution equivalent rights payments. |
EARNINGS PER COMMON UNIT (Table
EARNINGS PER COMMON UNIT (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Basic and Diluted Net Income Per Common Unit | A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below: Year Ended December 31, 2022 2021 2020 (In thousands, except per unit amounts) Net income (loss) attributable to the period $ 151,673 $ 57,939 $ (192,304) Less: net income (loss) allocated to participating securities (1) 365 193 44 Net income (loss) attributable to common unitholders $ 151,308 $ 57,746 $ (192,348) Weighted average common units outstanding: Basic weighted average common units outstanding 75,612 68,319 67,686 Effect of dilutive securities: Potential common units issuable (2) 67 72 — Diluted weighted average common units outstanding 75,679 68,391 67,686 Net income (loss) per common unit, basic $ 2.00 $ 0.85 $ (2.84) Net income (loss) per common unit, diluted $ 2.00 $ 0.85 $ (2.84) (1) Restricted stock units with non-forfeitable distribution equivalent rights granted to employees are considered participating securities. |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022, 2021 and 2020 are as follows: Year Ended December 31, 2022 2021 2020 (In thousands) Current income tax provision (benefit): Federal $ 15,929 $ 1,218 $ — State 1,074 303 — Total current income tax provision (benefit) 17,003 1,521 — Deferred income tax provision (benefit): Federal (49,656) — 142,466 State — — — Total deferred income tax provision (benefit) (49,656) — 142,466 Total provision (benefit) from income taxes $ (32,653) $ 1,521 $ 142,466 Effective tax rates (5.2) % 0.6 % (279.6) % |
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, 2022 2021 2020 (In thousands) Income tax expense (benefit) at the federal statutory rate (21%) $ 130,694 $ 54,221 $ (10,699) Impact of nontaxable noncontrolling interest (105,699) (41,735) 233 State income tax expense (benefit), net of federal tax effect 846 262 — Change in valuation allowance (58,443) (11,175) 152,898 Other, net (51) (52) 34 Provision for (benefit from) income taxes $ (32,653) $ 1,521 $ 142,466 |
Schedule of Deferred Tax Assets and Liabilities | The components of the Partnership’s deferred tax assets and liabilities as of December 31, 2022 and 2021 are as follows: Year Ended December 31, 2022 2021 (In thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 70 $ 6,014 Investment in the Operating Company 148,003 163,065 Total deferred tax assets 148,073 169,079 Valuation allowance (98,417) (169,079) Net deferred tax assets 49,656 — Net deferred tax assets (liabilities) $ 49,656 $ — |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments | As of December 31, 2022, the Partnership 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/Mcf Per Day Index Weighted Average Differential Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Strike Price OIL Jan. - Mar. 2023 Puts (1) 12,000 WTI Cushing $— $— $— $— $54.50 Apr. - Jun. 2023 Puts (2) 8,000 WTI Cushing $— $— $— $— $55.00 Jan. - Dec. 2023 Basis Swaps 4,000 Argus WTI Midland $1.05 $— $— $— $— NATURAL GAS Jan. - Dec. 2023 Basis Swaps 30,000 Waha Hub $(1.33) $— $— $— $— Jan. - Dec. 2024 Basis Swaps 20,000 Waha Hub $(1.23) $— $— $— $— (1) Includes a deferred premium at a weighted average price of $1.82/Bbl. (2) Includes a deferred premium at a weighted average price of $1.79/Bbl. |
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, 2022 2021 2020 (In thousands) Gain (loss) on derivative instruments $ (18,138) $ (69,409) $ (63,591) Net cash receipts (payments) on derivatives (1) $ (31,319) $ (92,585) $ (36,998) |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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 Partnership’s consolidated balance sheets as of December 31, 2022 and December 31, 2021. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. 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 As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 |
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 Partnership’s consolidated balance sheets as of December 31, 2022 and December 31, 2021. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. 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 As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 |
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 Partnership’s consolidated balance sheets as of December 31, 2022 and December 31, 2021. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. 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 As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 |
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, 2022 December 31, 2021 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Debt: Revolving credit facility $ 152,000 $ 152,000 $ 304,000 $ 304,000 5.375% senior notes due 2027 (1) $ 424,895 $ 411,634 $ 472,727 $ 498,992 (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, 2022 | |
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, 2022 2021 (In thousands) Oil and natural gas interests: Subject to depletion $ 2,167,598 $ 1,873,418 Not subject to depletion 1,297,221 1,640,172 Gross oil and natural gas interests 3,464,819 3,513,590 Accumulated depletion and impairment (720,234) (599,163) Oil and natural gas interests, net 2,744,585 2,914,427 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 2,750,273 $ 2,920,115 Balance of costs not subject to depletion: Incurred in 2022 $ 37,456 Incurred in 2021 478,747 Incurred in 2020 55,041 Prior 725,977 Total not subject to depletion $ 1,297,221 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2022 2021 (In thousands) Oil and natural gas interests: Proved $ 2,167,598 $ 1,873,418 Unproved 1,297,221 1,640,172 Total oil and natural gas interests 3,464,819 3,513,590 Accumulated depletion and impairment (720,234) (599,163) Net oil and natural gas interests capitalized $ 2,744,585 $ 2,914,427 |
Schedule of Cost Incurred in Oil and Gas Property Acquisition Activities | Costs incurred in oil and natural gas property acquisition activities are as follows: December 31, 2022 2021 2020 (In thousands) Acquisition costs: Proved properties $ 46,307 $ 138,882 $ 9,509 Unproved properties 16,624 479,041 56,169 Total $ 62,931 $ 617,923 $ 65,678 |
Schedule of Changes in Estimated Proved Reserves | The changes in estimated proved reserves are as follows: Oil Natural Gas Natural Gas Liquids Total (MBOE) (In thousands) Proved Developed and Undeveloped Reserves: As of December 31, 2019 54,420 95,774 18,564 88,946 Purchase of reserves in place 491 507 113 689 Extensions and discoveries 15,415 23,982 4,424 23,836 Revisions of previous estimates (6,685) 11,043 763 (4,082) Divestitures (155) (370) (63) (280) Production (5,956) (11,486) (1,848) (9,718) 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 Proved Developed Reserves: December 31, 2020 40,220 93,617 16,724 72,547 December 31, 2021 49,280 134,485 19,476 91,170 December 31, 2022 54,817 161,119 25,621 107,291 Proved Undeveloped Reserves: December 31, 2020 17,310 25,833 5,229 26,845 December 31, 2021 19,960 49,205 8,557 36,718 December 31, 2022 24,187 48,845 9,281 41,609 |
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 Partnership’s proved oil and natural gas reserves as of December 31, 2022, 2021 and 2020: December 31, 2022 2021 2020 (In thousands) Future cash inflows $ 10,072,969 $ 5,763,433 $ 2,460,052 Future production taxes (729,256) (416,761) (181,067) Future income tax expense (1,465,160) (572,991) (22,993) Future net cash flows 7,878,553 4,773,681 2,255,992 10% discount to reflect timing of cash flows (4,424,457) (2,680,564) (1,232,398) Standardized measure of discounted future net cash flows $ 3,454,096 $ 2,093,117 $ 1,023,594 |
Schedule of Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids | The following table presents the weighted average first-day-of–the-month prices for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows: December 31, 2022 2021 2020 Oil (per Bbl) $ 95.04 $ 64.87 $ 37.61 Natural gas (per Mcf) $ 5.74 $ 2.97 $ 0.34 Natural gas liquids (per Bbl) $ 38.95 $ 25.93 $ 11.65 |
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 Partnership’s proved reserves are as follows: December 31, 2022 2021 2020 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 2,093,117 $ 1,023,594 $ 1,318,388 Purchase of minerals in place 30,331 170,205 10,781 Divestiture of reserves (30,076) (4,402) (3,481) Sales of oil and natural gas, net of production costs (781,604) (468,976) (227,137) Extensions and discoveries 844,010 615,762 280,486 Net changes in prices and production costs 1,131,202 863,458 (465,582) Revisions of previous quantity estimates 309,338 45,788 (87,614) Net changes in income taxes (393,652) (243,186) 59,754 Accretion of discount 234,717 103,446 138,901 Net changes in timing of production and other 16,713 (12,572) (902) Standardized measure of discounted future net cash flows at the end of the period $ 3,454,096 $ 2,093,117 $ 1,023,594 |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Details) - Diamondback Energy, Inc. - Viper Energy Partners LP | 12 Months Ended |
Dec. 31, 2022 | |
Limited Partners' Capital Account [Line Items] | |
Percent of general partner interest | 100% |
Percent of limited partnership interest | 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, 2022 USD ($) $ / Boe | Dec. 31, 2021 USD ($) $ / Boe | Dec. 31, 2020 USD ($) $ / Boe | |
Debt Instrument [Line Items] | |||
Average depletion rate per barrel equivalent unit of production | $ / Boe | 9.86 | 10.04 | 10.34 |
Depletion for oil and natural gas properties | $ 121,071 | $ 102,987 | $ 100,501 |
Debt issuance costs, net of accumulated amortizations | 9,700 | 9,600 | |
Debit issuance costs, accumulated amortization | $ 9,500 | $ 6,800 | |
Senior Notes | 5.375% senior unsecured notes due 2027 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate, stated percentage | 5.375% |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Related Party Transactions (Details) - Swallowtail Acquisition Lease Bonus - Affiliated Entity $ in Millions | 12 Months Ended | |
Dec. 31, 2022 USD ($) lease | Dec. 31, 2021 USD ($) | |
Related Party Transaction [Line Items] | ||
Related party transaction, amounts of transaction | $ | $ 23.4 | $ 1.3 |
Number of leases, related party lease bonus | lease | 2 |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Accounting Policies [Abstract] | ||
Interest payable | $ 3,972 | $ 4,430 |
Ad valorem taxes payable | 12,492 | 6,201 |
Derivatives instruments payable | 1,684 | 8,879 |
Other | 1,452 | 999 |
Total accrued liabilities | $ 19,600 | $ 20,509 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations (Details) - Customer Concentration Risk - Royalty Interest Revenue | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Trafigura Trading LLC | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 17% | 23% | |
Shell Trading | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 14% | 16% | 13% |
Vitol Midstream Pipeline LLC | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 14% | 12% | 14% |
Concho Resources, Inc | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 11% |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accounting Policies [Abstract] | |||
Interest or penalties associated with uncertain tax positions | $ 0 | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_9
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-controlling Interest (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Limited Partners | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Change in ownership of consolidated subsidiaries, net | $ (58,253) | $ 93,473 | $ 34,087 |
REVENUE FROM CONTRACTS WITH C_3
REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Revenue [Line Items] | |||
Total royalty income | $ 837,976 | $ 501,534 | $ 246,981 |
Oil income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | 667,281 | 397,513 | 217,859 |
Natural gas income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | 83,149 | 49,197 | 9,024 |
Natural gas liquids income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | $ 87,546 | $ 54,824 | $ 20,098 |
ACQUISITIONS AND DIVESTITURES -
ACQUISITIONS AND DIVESTITURES - Acquisitions (Details) shares in Thousands, $ in Millions | 12 Months Ended | |||
Oct. 01, 2021 USD ($) a shares | Dec. 31, 2022 USD ($) a | Dec. 31, 2021 USD ($) a | Dec. 31, 2020 USD ($) a | |
2022 Acquisition Permian Basin | ||||
Business Acquisition [Line Items] | ||||
Net royalty (acres) | 375 | |||
Aggregate purchase price | $ | $ 65.9 | |||
Swallowtail Acquisition | ||||
Business Acquisition [Line Items] | ||||
Number of shares issued (in shares) | shares | 15,250 | |||
Payments for asset acquisitions | $ | $ 225.3 | |||
Percentage of acreage acquired | 62% | |||
Payment of contingent consideration | $ | $ 190 | |||
Swallowtail Acquisition | Northern Midland Basin | ||||
Business Acquisition [Line Items] | ||||
Net royalty (acres) | 2,313 | |||
Other 2021 Acquisitions | ||||
Business Acquisition [Line Items] | ||||
Net royalty (acres) | 392 | |||
Aggregate purchase price | $ | $ 55.1 | |||
Gross acres (acres) | 1,277 | |||
2020 Acquisitions | ||||
Business Acquisition [Line Items] | ||||
Net royalty (acres) | 417 | |||
Aggregate purchase price | $ | $ 64.2 | |||
Gross acres (acres) | 4,948 |
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 ($) a | Mar. 31, 2022 USD ($) a | Sep. 30, 2022 a | |
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 | ||
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 | ||
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 | $ | $ 53.8 |
OIL AND NATURAL GAS INTERESTS_2
OIL AND NATURAL GAS INTERESTS (Details) | 12 Months Ended | |||
Dec. 31, 2022 USD ($) a | Dec. 31, 2021 USD ($) a | Dec. 31, 2020 USD ($) | Dec. 31, 2019 USD ($) | |
Property, Plant and Equipment [Line Items] | ||||
Subject to depletion | $ 2,167,598,000 | $ 1,873,418,000 | ||
Not subject to depletion | 1,297,221,000 | 1,640,172,000 | ||
Gross oil and natural gas interests | 3,464,819,000 | 3,513,590,000 | ||
Accumulated depletion and impairment | (720,234,000) | (599,163,000) | ||
Oil and natural gas interests, net | 2,744,585,000 | 2,914,427,000 | ||
Land | 5,688,000 | 5,688,000 | ||
Property, net | 2,750,273,000 | 2,920,115,000 | ||
Balance of costs not subject to depletion: | $ 37,456,000 | $ 478,747,000 | $ 55,041,000 | $ 725,977,000 |
Net royalty acres | a | 26,315 | 27,027 | ||
Impairment | $ 0 | $ 0 | $ 69,202,000 | |
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, 2022 | Dec. 31, 2021 |
Line of Credit Facility [Line Items] | ||
Unamortized debt issuance costs | $ (1,306) | $ (1,757) |
Unamortized discount | (4,149) | (5,454) |
Long-term debt, net | 576,895 | 776,727 |
Revolving credit facility | Line of Credit | ||
Line of Credit Facility [Line Items] | ||
Long term debt gross | $ 152,000 | 304,000 |
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 | $ 479,938 |
DEBT - Additional Information (
DEBT - Additional Information (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Nov. 18, 2022 | |
5.375% senior unsecured notes due 2027 | Senior Notes | ||||
Line of Credit Facility [Line Items] | ||||
Repurchased face amount | $ 49,600,000 | |||
Repurchase amount | 49,000,000 | |||
Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $ 2,000,000,000 | |||
Current borrowing capacity | $ 580,000,000 | |||
Other commitment | 500,000,000 | |||
Amount outstanding under credit facility | 152,000,000 | |||
Remaining borrowing capacity | $ 348,000,000 | |||
Weighted average interest rate | 4.22% | 2.35% | 2.20% | |
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 | LIBOR | ||||
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 | LIBOR | ||||
Line of Credit Facility [Line Items] | ||||
Debt instrument applicable margin | 2% | |||
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% | |||
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 | LIBOR | ||||
Line of Credit Facility [Line Items] | ||||
Debt instrument applicable margin | 3% | |||
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% |
DEBT - Financial Covenants (Det
DEBT - Financial Covenants (Details) - Operating Company Revolving Credit Facility | Dec. 31, 2022 |
Maximum | |
Line of Credit Facility [Line Items] | |
Ratio of total net debt to EBITDAX, as defined in the credit agreement | 4 |
Ratio of secured debt to EBITDAX, as defined in the credit agreement | 2.5 |
Minimum | |
Line of Credit Facility [Line Items] | |
Ratio of current assets to liabilities, as defined in the credit agreement | 1 |
UNITHOLDERS_ EQUITY AND DISTR_3
UNITHOLDERS’ EQUITY AND DISTRIBUTIONS - Additional Information (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Feb. 17, 2023 | |
Limited Partners' Capital Account [Line Items] | ||||
Amount of shares repurchased | $ 150,593,000 | $ 45,999,000 | $ 24,026,000 | |
Cash Distribution | ||||
Limited Partners' Capital Account [Line Items] | ||||
Cash distributions, distribution period after quarter end | 60 days | |||
Common Unit Repurchase Program | ||||
Limited Partners' Capital Account [Line Items] | ||||
Amount of shares repurchased | $ 150,600,000 | $ 46,000,000 | $ 24,000,000 | |
Remaining authorized repurchase amount | $ 529,400,000 | |||
Diamondback Energy, Inc. | ||||
Limited Partners' Capital Account [Line Items] | ||||
Shares converted (in shares) | 1 | |||
Diamondback Energy, Inc. | Viper Energy Partners LP | ||||
Limited Partners' Capital Account [Line Items] | ||||
Percent of limited partnership interest | 56% | |||
Percentage by noncontrolling owners | 55% | |||
Common Units | ||||
Limited Partners' Capital Account [Line Items] | ||||
Limited partners' capital account, units issued (in shares) | 73,229,645 | 78,546,403 | ||
Limited partners' capital account, units outstanding (in shares) | 73,229,645 | 78,546,403 | ||
Shares issued (in shares) | 1 | |||
Common Units | Common Unit Repurchase Program | ||||
Limited Partners' Capital Account [Line Items] | ||||
Authorized amount in repurchase program | $ 750,000,000 | |||
Common Units | Diamondback Energy, Inc. | ||||
Limited Partners' Capital Account [Line Items] | ||||
Limited partners' capital account, units outstanding (in shares) | 731,500 | |||
Class B Units | ||||
Limited Partners' Capital Account [Line Items] | ||||
Limited partners' capital account, units issued (in shares) | 90,709,946 | 90,709,946 | ||
Limited partners' capital account, units outstanding (in shares) | 90,709,946 | 90,709,946 | 90,709,946 | |
Shares converted (in shares) | 1 | |||
Class B Units | Diamondback Energy, Inc. | ||||
Limited Partners' Capital Account [Line Items] | ||||
Limited partners' capital account, units outstanding (in shares) | 90,709,946 |
UNITHOLDERS_ EQUITY AND DISTR_4
UNITHOLDERS’ EQUITY AND DISTRIBUTIONS - Ownership Interest in Subsidiary Changes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Net income (loss) attributable to the Partnership | $ 151,673 | $ 57,939 | $ (192,304) |
Limited Partners | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Net income (loss) attributable to the Partnership | 151,673 | 57,939 | (192,304) |
Change in ownership of consolidated subsidiaries | 58,253 | (93,473) | (34,087) |
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest | $ 209,926 | $ (35,534) | $ (226,391) |
UNITHOLDERS_ EQUITY AND DISTR_5
UNITHOLDERS’ EQUITY AND DISTRIBUTIONS - Schedule of Partnership Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||||||||||||||
Nov. 03, 2022 | Jul. 26, 2022 | Apr. 27, 2022 | Feb. 16, 2022 | Oct. 27, 2021 | Jul. 28, 2021 | Apr. 27, 2021 | Feb. 19, 2021 | Oct. 28, 2020 | Jul. 29, 2020 | Apr. 30, 2020 | Feb. 07, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Distribution Amount | $ 182,470 | $ 75,749 | $ 45,630 | ||||||||||||
Common Units | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Limited partners' capital account, units outstanding (in shares) | 73,229,645 | 78,546,403 | |||||||||||||
Common Units | Diamondback Energy, Inc. | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Limited partners' capital account, units outstanding (in shares) | 731,500 | ||||||||||||||
Cash Distribution | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Cash distribution, amount per Common Unit (in USD per share) | $ 0.49 | $ 0.81 | $ 0.67 | $ 0.47 | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | $ 0.10 | $ 0.03 | $ 0.10 | $ 0.45 | |||
Cash Distribution | Operating Company Units | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Cash distribution, amount per Common Unit (in USD per share) | $ 0.52 | $ 0.87 | $ 0.70 | $ 0.47 | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | $ 0.10 | $ 0.03 | $ 0.10 | $ 0.45 | |||
Distribution Amount | $ 47,170 | $ 78,918 | $ 63,497 | $ 42,634 | $ 34,469 | $ 29,936 | $ 22,678 | $ 12,699 | $ 9,072 | $ 2,720 | $ 9,074 | $ 40,819 | |||
Cash Distribution | Common Units | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Distribution Amount | $ 36,076 | $ 60,626 | $ 51,680 | $ 36,238 | $ 30,118 | $ 21,235 | $ 16,230 | $ 9,162 | $ 6,805 | $ 2,034 | $ 6,790 | $ 30,543 |
EARNINGS PER COMMON UNIT (Detai
EARNINGS PER COMMON UNIT (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |||
Net income (loss) attributable to the period | $ 151,673 | $ 57,939 | $ (192,304) |
Less: net income (loss) allocated to participating securities | 365 | 193 | 44 |
Net income (loss) attributable to common unitholders | $ 151,308 | $ 57,746 | $ (192,348) |
Basic weighted average common units outstanding (in shares) | 75,612,000 | 68,319,000 | 67,686,000 |
Effect of dilutive securities: | |||
Potential common units issuable (in shares) | 67,000 | 72,000 | 0 |
Diluted weighted average common units outstanding (in shares) | 75,679,000 | 68,391,000 | 67,686,000 |
Net income (loss) per common unit, basic (dollars per shares) | $ 2 | $ 0.85 | $ (2.84) |
Net income (loss) per common unit, diluted (dollars per shares) | $ 2 | $ 0.85 | $ (2.84) |
Antidilutive securities, restricted stock units (in shares) | 0 | 10,160 | 0 |
INCOME TAXES - Components of Pr
INCOME TAXES - Components of Provision for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Current income tax provision (benefit): | |||
Federal | $ 15,929 | $ 1,218 | $ 0 |
State | 1,074 | 303 | 0 |
Total current income tax provision (benefit) | 17,003 | 1,521 | 0 |
Deferred income tax provision (benefit): | |||
Federal | (49,656) | 0 | 142,466 |
State | 0 | 0 | 0 |
Total deferred income tax provision (benefit) | (49,656) | 0 | 142,466 |
Total provision (benefit) from income taxes | $ (32,653) | $ 1,521 | $ 142,466 |
Effective tax rates | (5.20%) | 0.60% | (279.60%) |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Statutory Federal Income tax (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense (benefit) at the federal statutory rate (21%) | $ 130,694 | $ 54,221 | $ (10,699) |
Impact of nontaxable noncontrolling interest | (105,699) | (41,735) | 233 |
State income tax expense (benefit), net of federal tax effect | 846 | 262 | 0 |
Change in valuation allowance | (58,443) | (11,175) | 152,898 |
Other, net | (51) | (52) | 34 |
Total provision (benefit) from income taxes | $ (32,653) | $ 1,521 | $ 142,466 |
INCOME TAXES - Deferred Tax Ass
INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Deferred tax assets: | ||
Net operating loss and capital loss carryforwards | $ 70,000 | $ 6,014,000 |
Investment in the Operating Company | 148,003,000 | 163,065,000 |
Total deferred tax assets | 148,073,000 | 169,079,000 |
Valuation allowance | (98,417,000) | (169,079,000) |
Net deferred tax assets | 49,656,000 | 0 |
Net deferred tax assets (liabilities) | $ 49,656,000 | $ 0 |
INCOME TAXES - Additional Infor
INCOME TAXES - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
Deferred tax assets, net | $ 49,656 | $ 0 | |
Federal net operating loss carryforwards (approximately) | 100 | ||
Valuation allowance decrease | 49,700 | ||
State income tax expense | $ 1,074 | $ 303 | $ 0 |
DERIVATIVES - Open Derivative P
DERIVATIVES - Open Derivative Positions (Details) | 12 Months Ended |
Dec. 31, 2022 $ / bbl bbl | |
OIL | 2023 | Jan. - Mar. | WTI Cushing | Puts | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 12,000 |
Weighted Average Differential (USD per Bbl) | 0 |
Weighted Average Fixed Price (USD per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl) | 0 |
Weighted Average Ceiling Price (USD per Bbl) | 0 |
Strike price (USD per bbl) | 54.50 |
Deferred premium at a weighted average price (USD per Bbl) | 1.82 |
OIL | 2023 | Apr. - Jun. | WTI Cushing | Puts | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 8,000 |
Weighted Average Differential (USD per Bbl) | 0 |
Weighted Average Fixed Price (USD per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl) | 0 |
Weighted Average Ceiling Price (USD per Bbl) | 0 |
Strike price (USD per bbl) | 55 |
Deferred premium at a weighted average price (USD per Bbl) | 1.79 |
OIL | 2023 | Jan. - Dec. | Argus WTI Midland | Basis Swaps | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 4,000 |
Weighted Average Differential (USD per Bbl) | 1.05 |
Weighted Average Fixed Price (USD per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl) | 0 |
Weighted Average Ceiling Price (USD per Bbl) | 0 |
Strike price (USD per bbl) | 0 |
NATURAL GAS | 2023 | Jan. - Dec. | Waha Hub | Basis Swaps | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 30,000 |
Weighted Average Differential (USD per Bbl) | (1.33) |
Weighted Average Fixed Price (USD per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl) | 0 |
Weighted Average Ceiling Price (USD per Bbl) | 0 |
Strike price (USD per bbl) | 0 |
NATURAL GAS | 2024 | Jan. - Dec. | Waha Hub | Basis Swaps | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 20,000 |
Weighted Average Differential (USD per Bbl) | (1.23) |
Weighted Average Fixed Price (USD per Bbl) | 0 |
Weighted Average Floor Price (USD per Bbl) | 0 |
Weighted Average Ceiling Price (USD per Bbl) | 0 |
Strike price (USD per bbl) | 0 |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Gain (loss) on derivative instruments | $ (18,138) | $ (69,409) | $ (63,591) |
Net cash receipts (payments) on derivatives | (31,319) | $ (92,585) | $ (36,998) |
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, 2022 | Dec. 31, 2021 |
Current Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | $ 13,296 | $ 1,921 |
Gross Amounts Offset in Balance Sheet | (3,968) | (1,921) |
Net Fair Value Presented in Balance Sheet | 9,328 | 0 |
Noncurrent Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 1,911 | |
Gross Amounts Offset in Balance Sheet | (1,469) | |
Net Fair Value Presented in Balance Sheet | 442 | |
Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 3,968 | 5,338 |
Gross Amounts Offset in Balance Sheet | (3,968) | (1,921) |
Net Fair Value Presented in Balance Sheet | 0 | 3,417 |
Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 1,476 | |
Gross Amounts Offset in Balance Sheet | (1,469) | |
Net Fair Value Presented in Balance Sheet | 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 | |
Level 1 | Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 0 | 0 |
Level 1 | Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 0 | |
Level 2 | Current Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 13,296 | 1,921 |
Level 2 | Noncurrent Assets | ||
Assets: | ||
Derivative Asset, Fair Value, Gross Asset | 1,911 | |
Level 2 | Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 3,968 | 5,338 |
Level 2 | Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 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 | |
Level 3 | Current Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | 0 | $ 0 |
Level 3 | Noncurrent Liabilities | ||
Liabilities: | ||
Total Gross Fair Value | $ 0 |
FAIR VALUE MEASUREMENTS - Fair
FAIR VALUE MEASUREMENTS - Fair Value of Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
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% | |
Carrying Value | Fair Value, Nonrecurring | Revolving credit facility | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, fair value | $ 152,000 | $ 304,000 |
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 | 424,895 | 472,727 |
Fair Value | Fair Value, Nonrecurring | Revolving credit facility | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, fair value | 152,000 | 304,000 |
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 | $ 411,634 | $ 498,992 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - $ / shares | 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 | Oct. 28, 2020 | Jul. 29, 2020 | Apr. 30, 2020 | Feb. 07, 2020 |
Subsequent Event | Fixed Dividend | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Dividends payable (usd per share) | $ 0.25 | ||||||||||||
Subsequent Event | Variable Dividend | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Dividends payable (usd per share) | 0.24 | ||||||||||||
Cash Distribution | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Cash distribution, amount per Common Unit (in USD per share) | $ 0.49 | $ 0.81 | $ 0.67 | $ 0.47 | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | $ 0.10 | $ 0.03 | $ 0.10 | $ 0.45 | |
Cash Distribution | Subsequent Event | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Cash distribution, amount per Common Unit (in USD per share) | $ 0.49 |
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, 2022 | Dec. 31, 2021 |
Oil and natural gas interests: | ||
Proved | $ 2,167,598 | $ 1,873,418 |
Unproved | 1,297,221 | 1,640,172 |
Total oil and natural gas interests | 3,464,819 | 3,513,590 |
Accumulated depletion and impairment | (720,234) | (599,163) |
Net oil and natural gas interests capitalized | $ 2,744,585 | $ 2,914,427 |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract] | |||
Proved properties | $ 46,307 | $ 138,882 | $ 9,509 |
Unproved properties | 16,624 | 479,041 | 56,169 |
Total | $ 62,931 | $ 617,923 | $ 65,678 |
SUPPLEMENTAL INFORMATION ON O_5
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Changes in Estimated Proved Reserves (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands | 12 Months Ended | ||
Dec. 31, 2022 MBoe MBbls MMcf | Dec. 31, 2021 MBoe MMcf MBbls | Dec. 31, 2020 MBoe MMcf MBbls | |
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Proved Developed and Undeveloped Reserve, Net (Energy), Beginning Balance | MBoe | 127,888 | 99,392 | 88,946 |
Purchase of reserves in place | MBoe | 1,006 | 9,102 | 689 |
Extensions and discoveries | MBoe | 25,858 | 30,981 | 23,836 |
Revisions of previous estimates | MBoe | 8,477 | (918) | (4,082) |
Divestitures | MBoe | (2,047) | (409) | (280) |
Production | MBoe | (12,282) | (10,260) | (9,718) |
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance | MBoe | 148,900 | 127,888 | 99,392 |
Proved developed reserves (energy) | MBoe | 107,291 | 91,170 | 72,547 |
Proved undeveloped reserves (energy) | MBoe | 41,609 | 36,718 | 26,845 |
Oil | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | 69,240 | 57,530 | 54,420 |
Purchase of reserves in place | 599 | 5,246 | 491 |
Extensions and discoveries | 15,714 | 17,256 | 15,415 |
Revisions of previous estimates | 1,453 | (4,544) | (6,685) |
Divestitures | (905) | (180) | (155) |
Production | (7,097) | (6,068) | (5,956) |
End of period | 79,004 | 69,240 | 57,530 |
Proved developed reserves (volume) | 54,817 | 49,280 | 40,220 |
Proved undeveloped reserve (volume) | 24,187 | 19,960 | 17,310 |
Natural Gas Liquids | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | 28,033 | 21,953 | 18,564 |
Purchase of reserves in place | 209 | 2,264 | 113 |
Extensions and discoveries | 5,281 | 7,182 | 4,424 |
Revisions of previous estimates | 4,483 | (1,339) | 763 |
Divestitures | (564) | (114) | (63) |
Production | (2,540) | (1,913) | (1,848) |
End of period | 34,902 | 28,033 | 21,953 |
Proved developed reserves (volume) | 25,621 | 19,476 | 16,724 |
Proved undeveloped reserve (volume) | 9,281 | 8,557 | 5,229 |
Natural Gas | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | MMcf | 183,690 | 119,450 | 95,774 |
Purchase of reserves in place | MMcf | 1,186 | 9,549 | 507 |
Extensions and discoveries | MMcf | 29,177 | 39,256 | 23,982 |
Revisions of previous estimates | MMcf | 15,248 | 29,788 | 11,043 |
Divestitures | MMcf | (3,469) | (681) | (370) |
Production | MMcf | (15,868) | (13,672) | (11,486) |
End of period | MMcf | 209,964 | 183,690 | 119,450 |
Proved developed reserves (volume) | MMcf | 161,119 | 134,485 | 93,617 |
Proved undeveloped reserve (volume) | MMcf | 48,845 | 49,205 | 25,833 |
SUPPLEMENTAL INFORMATION ON O_6
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Additional Information (Details) MBoe in Thousands | 12 Months Ended | ||
Dec. 31, 2022 MBoe well | Dec. 31, 2021 MBoe well | Dec. 31, 2020 MBoe well | |
Extractive Industries [Abstract] | |||
Oil and gas, development well drilled, net productive, number | well | 636 | 407 | 652 |
New proved undeveloped location | well | 199 | 336 | 299 |
MBOE of PUDs downgraded due to positive revisions | 7,007 | 11,263 | |
MBOE of PUDs downgraded due to price and performance revision | 15,484 | 10,345 | |
MBOE of PUDs downgraded from non-operated properties | 114 | ||
MBOE of PUDs downgraded due to changes in the development plan and optimization of the inventory | 804 |
SUPPLEMENTAL INFORMATION ON O_7
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 10,072,969 | $ 5,763,433 | $ 2,460,052 | |
Future production taxes | (729,256) | (416,761) | (181,067) | |
Future income tax expense | (1,465,160) | (572,991) | (22,993) | |
Future net cash flows | 7,878,553 | 4,773,681 | 2,255,992 | |
10% discount to reflect timing of cash flows | (4,424,457) | (2,680,564) | (1,232,398) | |
Standardized measure of discounted future net cash flows | $ 3,454,096 | $ 2,093,117 | $ 1,023,594 | $ 1,318,388 |
SUPPLEMENTAL INFORMATION ON O_8
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, 2022 $ / bbl $ / Mcf | Dec. 31, 2021 $ / bbl $ / Mcf | Dec. 31, 2020 $ / 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 | 95.04 | 64.87 | 37.61 |
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 | 5.74 | 2.97 | 0.34 |
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 | 38.95 | 25.93 | 11.65 |
SUPPLEMENTAL INFORMATION ON O_9
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
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 | $ 2,093,117 | $ 1,023,594 | $ 1,318,388 |
Purchase of minerals in place | 30,331 | 170,205 | 10,781 |
Divestiture of reserves | (30,076) | (4,402) | (3,481) |
Sales of oil and natural gas, net of production costs | (781,604) | (468,976) | (227,137) |
Extensions and discoveries | 844,010 | 615,762 | 280,486 |
Net changes in prices and production costs | 1,131,202 | 863,458 | (465,582) |
Revisions of previous quantity estimates | 309,338 | 45,788 | (87,614) |
Net changes in income taxes | (393,652) | (243,186) | 59,754 |
Accretion of discount | 234,717 | 103,446 | 138,901 |
Net changes in timing of production and other | 16,713 | (12,572) | (902) |
Standardized measure of discounted future net cash flows at the end of the period | $ 3,454,096 | $ 2,093,117 | $ 1,023,594 |