Cover
Cover - USD ($) $ in Billions | 12 Months Ended | |||
Dec. 31, 2021 | Feb. 18, 2022 | Jun. 30, 2021 | Dec. 31, 2020 | |
Entity Information [Line Items] | ||||
Document Type | 10-K | |||
Document Annual Report | true | |||
Document Period End Date | Dec. 31, 2021 | |||
Current Fiscal Year End Date | --12-31 | |||
Document Transition Report | false | |||
Entity File Number | 001-36505 | |||
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 1200 | |||
Entity Address, City or Town | Midland, | |||
Entity Address, State or Province | TX | |||
Entity Address, Postal Zip Code | 79701 | |||
City Area Code | 432 | |||
Local Phone Number | 221-7400 | |||
Title of 12(b) Security | Common 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 | $ 1.2 | |||
Entity Common Units, Units Outstanding | 76,966,203 | |||
Documents Incorporated by Reference | Documents Incorporated By Reference: None | |||
Amendment Flag | false | |||
Document Fiscal Year Focus | 2021 | |||
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, 2021 | |
Audit Information [Abstract] | |
Auditor Firm ID | 248 |
Auditor Name | GRANT THORNTON LLP |
Auditor Location | Oklahoma City, Oklahoma |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets: | ||
Cash and cash equivalents | $ 39,448 | $ 19,121 |
Royalty income receivable (net of allowance for credit losses) | 68,568 | 32,210 |
Royalty income receivable—related party | 2,144 | 1,998 |
Other current assets | 989 | 665 |
Total current assets | 111,149 | 53,994 |
Property: | ||
Oil and natural gas interests, full cost method of accounting ($1,640,172 and $1,364,906 excluded from depletion at December 31, 2021 and December 31, 2020, respectively) | 3,513,590 | 2,895,542 |
Land | 5,688 | 5,688 |
Accumulated depletion and impairment | (599,163) | (496,176) |
Property, net | 2,920,115 | 2,405,054 |
Other assets | 2,757 | 2,327 |
Total assets | 3,034,021 | 2,461,375 |
Current liabilities: | ||
Accounts payable | 69 | 43 |
Accrued liabilities | 20,980 | 18,262 |
Derivative instruments | 3,417 | 26,593 |
Total current liabilities | 24,466 | 44,898 |
Long-term debt, net | 776,727 | 555,644 |
Total liabilities | 801,193 | 600,542 |
Commitments and contingencies (Note 12) | ||
Unitholders’ equity: | ||
General Partner | 729 | 809 |
Common units (78,546,403 units issued and outstanding as of December 31, 2021 and 65,817,281 units issued and outstanding as of December 31, 2020) | 813,161 | 633,415 |
Class B units (90,709,946 units issued and outstanding December 31, 2021 and December 31, 2020) | 931 | 1,031 |
Total Viper Energy Partners LP unitholders’ equity | 814,821 | 635,255 |
Non-controlling interest | 1,418,007 | 1,225,578 |
Total equity | 2,232,828 | 1,860,833 |
Total liabilities and unitholders’ equity | $ 3,034,021 | $ 2,461,375 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Feb. 18, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion | $ 1,640,172 | $ 1,364,906 | |
Common Units | |||
Limited partners' capital account, units issued (in shares) | 78,546,403 | 65,817,281 | |
Limited partners' capital account, units outstanding (in shares) | 78,546,403 | 65,817,281 | |
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, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating income: | |||
Royalty income | $ 501,534 | $ 246,981 | $ 293,811 |
Lease bonus income | 2,763 | 2,585 | 4,117 |
Other operating income | 620 | 1,060 | 355 |
Total operating income | 504,917 | 250,626 | 298,283 |
Costs and expenses: | |||
Production and ad valorem taxes | 32,558 | 19,844 | 19,076 |
Depletion | 102,987 | 100,501 | 78,178 |
Impairment | 0 | 69,202 | 0 |
General and administrative expenses | 7,800 | 8,165 | 7,489 |
Total costs and expenses | 143,345 | 197,712 | 104,743 |
Income (loss) from operations | 361,572 | 52,914 | 193,540 |
Other income (expense): | |||
Interest expense, net | (34,044) | (33,000) | (21,076) |
Gain (loss) on derivative instruments, net | (69,409) | (63,591) | 0 |
Gain (loss) on revaluation of investment | 0 | (8,556) | 4,832 |
Other income, net | 79 | 1,286 | 2,332 |
Total other expense, net | (103,374) | (103,861) | (13,912) |
Income (loss) before income taxes | 258,198 | (50,947) | 179,628 |
Provision for (benefit from) income taxes | 1,521 | 142,466 | (41,582) |
Net income (loss) | 256,677 | (193,413) | 221,210 |
Net income (loss) attributable to non-controlling interest | 198,738 | (1,109) | 174,929 |
Net income (loss) attributable to Viper Energy Partners LP | $ 57,939 | $ (192,304) | $ 46,281 |
Net income (loss) attributable to common limited partner units: | |||
Basic (dollars per shares) | $ 0.85 | $ (2.84) | $ 0.75 |
Diluted (dollars per shares) | $ 0.85 | $ (2.84) | $ 0.75 |
Weighted average number of common limited partner units outstanding: | |||
Basic (in shares) | 68,319 | 67,686 | 61,744 |
Diluted (in shares) | 68,391 | 67,686 | 61,787 |
Revenue extensible list | Royalty [Member] |
Statement of Consolidated Unith
Statement of Consolidated Unitholders' Equity - USD ($) shares in Thousands, $ in Thousands | Total | Drop-Down Acquisition | General Partner | Non-Controlling Interest | Non-Controlling InterestDrop-Down Acquisition | Common Units | Common UnitsLimited Partners | Class B UnitsLimited Partners | Class B UnitsLimited PartnersDrop-Down Acquisition |
Beginning balance (in shares) at Dec. 31, 2018 | 51,654 | 72,419 | |||||||
Beginning balance at Dec. 31, 2018 | $ 1,237,042 | $ 1,000 | $ 694,940 | $ 540,112 | $ 990 | ||||
Increase (Decrease) in Partners' Capital | |||||||||
Net proceeds from the issuance of common units - public (in shares) | 10,925 | ||||||||
Net proceeds from the issuance of common units - public | 340,860 | $ 340,860 | |||||||
Common units issued for acquisition (in shares) | 5,152 | 18,291 | |||||||
Common units issued for acquisition | 124,012 | $ 497,412 | $ 497,162 | $ 124,012 | $ 250 | ||||
Offering costs | (221) | (221) | |||||||
Unit-based compensation | 1,822 | $ 1,822 | |||||||
Issuance of common units, net (in shares) | 75 | ||||||||
Distributions to public | (107,074) | $ (107,074) | |||||||
Distributions to Diamondback | (133,211) | (131,801) | (1,300) | $ (110) | |||||
Distributions to General Partner | (80) | (111) | 31 | ||||||
Change in ownership of consolidated subsidiaries, net | 4,001 | 19,055 | (15,054) | ||||||
Cash paid for tax withholding on vested common units | (353) | (353) | |||||||
Net income (loss) | 221,210 | 174,929 | $ 46,281 | ||||||
Ending balance (in shares) at Dec. 31, 2019 | 67,806 | 90,710 | |||||||
Ending 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 | |||||||
Issuance of common units, net (in shares) | 56 | ||||||||
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 | 34,087 | (34,087) | |||||||
Distribution equivalent rights payments | (44) | (44) | |||||||
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 | |||||||||
Common units issued for acquisition (in shares) | 15,250 | ||||||||
Common units issued for acquisition | 336,872 | $ 336,872 | |||||||
Unit-based compensation | 1,172 | $ 1,172 | |||||||
Issuance of common units, net (in shares) | 92 | ||||||||
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 | 93,473 | (93,473) | |||||||
Distribution equivalent rights payments | (193) | (193) | |||||||
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 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 256,677 | $ (193,413) | $ 221,210 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Deferred income tax expense (benefit) | 0 | 142,466 | (41,582) |
Depletion | 102,987 | 100,501 | 78,178 |
Impairment | 0 | 69,202 | 0 |
(Gain) loss on derivative instruments, net | 69,409 | 63,591 | 0 |
Net cash receipts (payments) on derivatives | (92,585) | (36,998) | 0 |
(Gain) loss on revaluation of investment | 0 | 8,556 | (4,832) |
Other | 4,710 | 3,589 | 2,800 |
Changes in operating assets and liabilities: | |||
Royalty income receivable | (36,358) | 25,879 | (19,266) |
Royalty income receivable—related party | (146) | 8,578 | (7,087) |
Other | 2,420 | 4,605 | 7,270 |
Net cash provided by (used in) operating activities | 307,114 | 196,556 | 236,691 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas interests | (281,176) | (65,678) | (530,572) |
Proceeds from sale of assets | 0 | 38,594 | 0 |
Proceeds from the sale of investments | 0 | 10,801 | 0 |
Net cash provided by (used in) investing activities | (281,176) | (16,283) | (530,572) |
Cash flows from financing activities: | |||
Proceeds from borrowings under credit facility | 330,000 | 104,000 | 590,500 |
Repayment on credit facility | (110,000) | (116,500) | (905,000) |
Proceeds from senior notes | 0 | 0 | 500,000 |
Repayment of senior notes | 0 | (19,697) | 0 |
Debt issuance costs | (2,885) | (111) | (10,863) |
Proceeds from public offerings | 0 | 0 | 340,860 |
Repurchased units as part of unit buyback | (45,999) | (24,026) | 0 |
Distributions to public | (75,942) | (45,674) | (107,074) |
Distributions to Diamondback | (100,685) | (62,282) | (133,211) |
Other | (100) | (464) | (405) |
Net cash provided by (used in) financing activities | (5,611) | (164,754) | 274,807 |
Net increase (decrease) in cash and cash equivalents | 20,327 | 15,519 | (19,074) |
Cash, cash equivalents and restricted cash at beginning of period | 19,121 | 3,602 | 22,676 |
Cash, cash equivalents and restricted cash at end of period | 39,448 | 19,121 | 3,602 |
Supplemental disclosure of cash flow information: | |||
Interest paid | 30,784 | 33,121 | 13,803 |
Supplemental disclosure of non—cash transactions: | |||
OpCo units issued for the Drop-Down transaction | 0 | 0 | 497,162 |
Common units issued for acquisition | $ 336,872 | $ 0 | $ 124,012 |
Organization and Basis of Prese
Organization and Basis of Presentation | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback beneficially owned an approximate 54% 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, 2021 | |
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, in 2020, the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressure in the first half of 2020, followed by a recovery in pricing and an increase in demand in the second half of 2020 and into 2021. However, the COVID-19 Delta variant emerged in March 2021 and became highly transmissible in July 2021, and the Omicron variant emerged in November 2021, which contributed to additional pricing volatility during the fourth quarter of 2021. 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 the particular circumstances. 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, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the 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. 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. The Partnership adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from 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 by considering 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. The adoption of ASU 2016-13 did not result in a material change to the Partnership’s allowance, and no cumulative-effect adjustment was made to beginning unitholders’ equity. At December 31, 2021 and December 31, 2020, 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. 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. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. 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. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. 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, 2021 and 2020, 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 $10.04, $10.34 and $9.95 for the years ended December 31, 2021, 2020 and 2019, respectively. Depletion for oil and natural gas properties was $103.0 million, $100.5 million and $78.2 million for the years ended December 31, 2021, 2020 and 2019, 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 on an annual basis 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 $9.6 million and $6.7 million, and accumulated amortization of those costs over the term of the credit agreement of $6.8 million and $4.4 million as of December 31, 2021, and 2020, 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. Accrued Liabilities Accrued liabilities consist of the following: December 31, 2021 2020 (In thousands) Interest payable $ 4,430 $ 4,311 Ad valorem taxes payable 6,201 6,501 Derivatives instruments payable 8,879 7,392 Other 1,470 58 Total accrued liabilities $ 20,980 $ 18,262 Concentrations The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenue in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2021, three purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (17%), Shell Trading (US) Company (“Shell Trading”) (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 (13%) and Concho Resources (11%). For the year ended December 31, 2019, three purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (27%), Concho Resources (16%) and Shell Trading (12%). 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, 2021, 2020 and 2019, 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 Partnership Distributions for further discussion of the change in ownership. Recent Accounting Pronouncements Recently Adopted Pronouncements In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”. This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted There are no recent accounting pronouncements not yet adopted. |
Revenue From Contracts With Cus
Revenue From Contracts With Customers | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Revenue From Contracts With Customers | REVENUE FROM CONTRACTS WITH CUSTOMERS 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, 2021, 2020 and 2019, 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, 2021 2020 2019 (In thousands) Oil income $ 397,513 $ 217,859 $ 264,376 Natural gas income 49,197 9,024 8,092 Natural gas liquids income 54,824 20,098 21,343 Total royalty income $ 501,534 $ 246,981 $ 293,811 |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2021 | |
Business Combinations And Divestitures [Abstract] | |
Acquisitions and Divestitures | ACQUISITIONS AND DIVESTITURES 2021 Activity 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 has an effective date of August 1, 2021. In accordance with the terms of the purchase agreement, the Partnership deposited $30.0 million into an escrow account in August 2021, which was released up on the closing of the transaction. 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. 2019 Activity Drop-Down Acquisition On October 1, 2019, the Partnership completed the acquisition of certain mineral and royalty interests from subsidiaries of Diamondback for approximately 18.3 million of its newly-issued Class B units, approximately 18.3 million newly-issued units of the Operating Company with a fair value of $497.2 million and $190.2 million in cash, after giving effect to closing adjustments for net title benefits (the ‘‘Drop-Down Acquisition’’). The mineral and royalty interests acquired in the Drop-Down Acquisition represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by Diamondback, and have an average net royalty interest of approximately 3.2% (the ‘‘Drop-Down Assets’’). The Partnership completed the acquisition on October 1, 2019 and funded the cash portion of the purchase price for the Drop-Down Assets through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. Santa Elena Acquisition On October 31, 2019, the Partnership completed the acquisition of certain mineral and royalty interests from Santa Elena (the ‘‘Santa Elena Acquisition’’), which assets were immediately contributed by the Partnership to the Operating Company. The assets acquired in the Santa Elena Acquisition represent approximately 1,366 net royalty acres across the Midland Basin with an average net royalty interest of approximately 5.6% and are primarily operated by Diamondback in Glasscock and Martin counties (the ‘‘Santa Elena Assets’’). At closing, the Partnership issued to Santa Elena approximately 5.2 million common units representing limited partner interests in the Partnership as consideration for the Santa Elena Assets, and the Operating Company issued to the Partnership approximately 5.2 million new units of the Operating Company with a fair value of $124.0 million. Other 2019 Acquisitions In addition, during the year ended December 31, 2019, the Partnership acquired, from unrelated third party sellers, mineral interests representing 136,012 gross (2,607 net royalty) acres for an aggregate of approximately $343.7 million. The Partnership funded these acquisitions with cash on hand, a portion of the net proceeds from its first quarter 2019 offering of common units and borrowings under the Operating Company’s revolving credit facility. Divestitures of Certain Non-Core Assets and Investments During 2020, the Partnership divested its equity interest in a limited partnership for approximately $10.8 million. This divestiture resulted in an immaterial loss. During the year ended December 31, 2020, the Partnership completed its divestiture of 370 net royalty acres of certain non-core Permian assets for an aggregate sale price of $38.4 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Partnership’s reserve base or depreciation, depletion and amortization rate. |
Oil and Natural Gas Interests
Oil and Natural Gas Interests | 12 Months Ended |
Dec. 31, 2021 | |
Extractive Industries [Abstract] | |
Oil and Natural Gas Interests | OIL AND NATURAL GAS INTERESTS Oil and natural gas interests include the following: December 31, 2021 2020 (In thousands) Oil and natural gas interests: Subject to depletion $ 1,873,418 $ 1,530,636 Not subject to depletion 1,640,172 1,364,906 Gross oil and natural gas interests 3,513,590 2,895,542 Accumulated depletion and impairment (599,163) (496,176) Oil and natural gas interests, net 2,914,427 2,399,366 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 2,920,115 $ 2,405,054 Balance of costs not subject to depletion: Incurred in 2021 $ 478,747 Incurred in 2020 55,041 Incurred in 2019 827,680 Incurred in 2018 278,704 Total not subject to depletion $ 1,640,172 As of December 31, 2021 and December 31, 2020, the Partnership had mineral and royalty interests representing 27,027 and 24,350 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 five 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, 2021 and 2019, 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, 2021 | |
Debt Disclosure [Abstract] | |
Debt | DEBT Long-term debt consisted of the following as of the dates indicated: December 31, 2021 2020 (In thousands) 5.375% senior unsecured notes due 2027 $ 479,938 $ 479,938 Revolving credit facility 304,000 84,000 Unamortized debt issuance costs (1,757) (2,058) Unamortized discount (5,454) (6,236) Total long-term debt $ 776,727 $ 555,644 The Operating Company’s Revolving Credit Facility On June 2, 2021, the Operating Company entered into the seventh amendment to the existing credit agreement, which (i) extended the maturity date under the credit agreement to June 2, 2025 , (ii) changed the interest rates applicable to the loans under the credit agreement and certain fees payable under the credit agreement, and (iii) added a financial covenant requiring the ratio of secured debt to EBITDAX (as each is defined in the credit agreement) to be not greater than 2.50 to 1.0. On November 15, 2021, the Operating Company entered into the eighth amendment to the existing credit agreement, which maintained the maximum amount of the revolving credit facility at $2.0 billion, reaffirmed the borrowing base of $580.0 million based on the Operating Company’s oil and natural gas reserves and other factors, and allowed the Operating Company to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be redetermined semi-annually in May and November. In addition, the Operating Company and Wells Fargo may each request up to three interim redeterminations of the borrowing base during any 12-month period. As of December 31, 2021, the Operating Company had elected a commitment amount of $500.0 million, with $304.0 million of outstanding borrowings and $196.0 million available for future borrowings under the Operating Company’s revolving credit facility. The outstanding borrowings under the credit agreement bear interest at a rate elected by the Operating Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternative base rate and from 2.00% to 3.00% per annum in the case of LIBOR, 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, which is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date. The loan is secured by substantially all the assets of the Partnership and the Operating Company. For the years ended December 31, 2021, 2020 and 2019, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was 2.35%, 2.20%, and 4.51%, respectively. 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 The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. |
Unitholders_ Equity and Distrib
Unitholders’ Equity and Distributions | 12 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
Unitholders’ Equity and Distributions | UNITHOLDERS’ EQUITY AND DISTRIBUTIONS The Partnership has General Partner and limited partner units. At December 31, 2021, the Partnership had a total of 78,546,403 common units 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 54% of the Partnership’s total units outstanding. Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 54% 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 partner previously established a common unit repurchase program pursuant to which it was authorized to repurchase, in the open market or in privately negotiated transactions, its common units having the initial aggregate purchase price of up to $100.0 million and the initial term ending on December 31, 2021. Prior to the expiration of the initial repurchase program, the board of directors of the Partnership’s general partner approved an increase to the common unit repurchase program to up to $150.0 million of the Partnership’s outstanding common units and extended the authorization indefinitely. The increased repurchase program went into effect on November 15, 2021. During the years ended December 31, 2021 and 2020, the Partnership repurchased approximately $46.0 million and $24.0 million of common units under the repurchase program, respectively. As of December 31, 2021, $80.0 million remains available for use to repurchase units under the repurchase program. The Partnership intends to purchase common units un der the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity 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. 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, 2021 2020 2019 (In thousands) Net income (loss) attributable to the Partnership $ 57,939 $ (192,304) $ 46,281 Change in ownership of consolidated subsidiaries (93,473) (34,087) (15,054) Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest $ (35,534) $ (226,391) $ 31,227 Cash Distributions Beginning with the first quarter of 2020, the board of directors of the General Partner revised the distribution policy to provide that the Operating Company would distribute a percentage of its available cash to its unitholders (including Diamondback and the Partnership) rather than all of its available cash as it had previously done. The Partnership in turn distributes all 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 Operating Company’s available cash generally equals its Adjusted EBITDA for the quarter, less cash needed for debt service and other 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, if any. The Partnership’s available cash for each quarter generally equals its Adjusted EBITDA (which is the Partnership’s proportional share of its available cash of the Operating Company for the quarter), less cash needed for the payment of income taxes by it, if any, and the preferred distribution. Immediately prior to the revisions to the distribution policy described above, the Operating Company’s policy was to distribute all of its available cash quarterly to its unitholders. The distribution policy changes noted above were made 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 board of directors of the General Partner may change the distribution policies at any time. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis. The following table presents cash distributions approved by the board of directors of the General Partner for the periods presented: Distributions (In thousands) Period Amount per Unit Percentage of Operating Company Available Cash Distributed Operating Company Distributions to Diamondback Common Unitholders (1) Declaration Date Unitholder Record Date Payment Date Q4 2018 $ 0.51 100 % $ 36,934 $ 26,382 January 30, 2019 February 19, 2019 February 25, 2019 Q1 2019 $ 0.38 100 % $ 27,519 $ 23,839 April 25, 2019 May 13, 2019 May 20, 2019 Q2 2019 $ 0.47 100 % $ 34,036 $ 29,483 July 28, 2019 August 14, 2019 August 21, 2019 Q3 2019 $ 0.46 100 % $ 33,312 $ 28,639 October 25, 2019 November 8, 2019 November 15, 2019 Q4 2019 $ 0.45 100 % $ 40,819 $ 30,543 February 7, 2020 February 21, 2020 February 28, 2020 Q1 2020 $ 0.10 25 % $ 9,074 $ 6,790 April 30, 2020 May 14, 2020 May 21, 2020 Q2 2020 $ 0.03 25 % $ 2,720 $ 2,034 July 29, 2020 August 13, 2020 August 20, 2020 Q3 2020 $ 0.10 50 % $ 9,072 $ 6,805 October 28, 2020 November 12, 2020 November 19, 2020 Q4 2020 $ 0.14 50 % $ 12,699 $ 9,162 February 19, 2021 March 4, 2021 March 11, 2021 Q1 2021 $ 0.25 60 % $ 22,678 $ 16,230 April 27, 2021 May 13, 2021 May 20, 2021 Q2 2021 $ 0.33 70 % $ 29,936 $ 21,235 July 28, 2021 August 12, 2021 August 19, 2021 Q3 2021 $ 0.38 70 % $ 34,469 $ 30,118 October 27, 2021 November 11, 2021 November 18, 2021 (1) Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback. 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, has entered into an agreement whereby special allocations of the Operating Company’s income and gains over losses and deductions (but before depletion) are to be made to Diamondback. This agreement was amended in December 2021 to shorten the remaining period of special allocations to Diamondback by one year, so that the special allocation period will end on December 31, 2022, rather than on December 31, 2023. These special income allocations will reduce the taxable income allocated to the Partnership’s common unitholders. |
Earnings Per Common Unit
Earnings Per Common Unit | 12 Months Ended |
Dec. 31, 2021 | |
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) of the Partnership for the years ended December 31, 2021, 2020 and 2019, since this is the amount of net income (loss) that is attributable to the Partnership’s common units. 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 Partnership 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, 2021 2020 2019 (In thousands, except per unit amounts) Net income (loss) attributable to the period $ 57,939 $ (192,304) $ 46,281 Less: net income (loss) allocated to participating securities (1) 193 (44) (117) Net income (loss) attributable to common unitholders $ 58,132 $ (192,348) $ 46,164 Weighted average common units outstanding: Basic weighted average common units outstanding 68,319 67,686 61,744 Effect of dilutive securities: Potential common units issuable (2) 72 — 43 Diluted weighted average common units outstanding 68,391 67,686 61,787 Net income (loss) per common unit, basic $ 0.85 $ (2.84) $ 0.75 Net income (loss) per common unit, diluted $ 0.85 $ (2.84) $ 0.75 (1) Distribution equivalent rights granted to employees are considered participating securities. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES The Partnership’s total income tax expense for the year ended December 31, 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of maintaining a valuation allowance on the Partnership’s deferred tax assets. 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. Total income tax benefit for the year ended December 31, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the revision of estimated deferred taxes recognized as a result of the Partnership’s change in tax status. The components of the provision for income taxes and effective tax rates for the years ended December 31, 2021, 2020 and 2019 are as follows: Year Ended December 31, 2021 2020 2019 (In thousands) Current income tax provision (benefit): Federal $ 1,218 $ — $ — State 303 — — Total current income tax provision (benefit) 1,521 — — Deferred income tax provision (benefit): Federal — 142,466 (41,582) State — — — Total deferred income tax provision (benefit) — 142,466 (41,582) Total provision (benefit) from income taxes $ 1,521 $ 142,466 $ (41,582) Effective tax rates 0.6 % (279.6) % (23.1) % A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2021 2020 2019 (In thousands) Income tax expense (benefit) at the federal statutory rate (21%) $ 54,221 $ (10,699) $ 37,722 Impact of nontaxable noncontrolling interest (41,735) 233 (36,735) State income tax expense (benefit), net of federal tax effect 262 — — Deferred taxes related to change in tax status — — (42,424) Change in valuation allowance (11,175) 152,898 — Other, net (52) 34 (145) Provision for (benefit from) income taxes $ 1,521 $ 142,466 $ (41,582) The components of the Partnership’s deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows: Year Ended December 31, 2021 2020 (In thousands) Deferred tax assets: Net operating loss and interest expense carryforwards (indefinite life carryforward) $ 6,014 $ 10,477 Investment in the Operating Company 163,065 150,127 Total deferred tax assets 169,079 160,604 Valuation allowance (169,079) (160,604) Net deferred tax assets — — Net deferred tax assets (liabilities) $ — $ — As of December 31, 2021 and 2020, the Partnership had no net deferred tax assets or deferred tax liabilities. Subsequent to the Partnership’s change in tax status, 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. At December 31, 2021, the Partnership had federal net operating loss carryforwards of approximately $28.6 million which may be carried forward indefinitely to offset future taxable income. As of December 31, 2021, the Partnership had a valuation allowance of approximately $169.1 million related to deferred tax assets the Partnership does not believe are more likely than not to be realized. Management considers the likelihood that the Partnership’s net operating losses and other deferred tax attributes will be utilized prior to their expiration, if applicable. The determination to record a valuation allowance was based on management’s assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the Partnership’s assessment resulted in application of a valuation allowance against the Partnership’s federal deferred tax assets as of March 31, 2020 and subsequent balance sheet dates within the years ended December 31, 2021 and 2020. In addition, a valuation allowance was maintained against state net operating loss carryforwards not anticipated to be utilized prior to expiration. The Partnership principally operates in the state of Texas. For the years ended December 31, 2021, the Partnership accrued $0.3 million state income tax expenses for its share of Texas margin tax attributable to the Partnership’s results which are included in a combined tax return filed by Diamondback. For the year ended December 31, 2020, the Partnership did not accrue any state income tax expenses. At December 31, 2021, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements. In addition to the 2019 through 2021 tax years, our 2018 tax year during which we elected to be treated as a corporation for income tax purposes, remains open to examination by tax authorities. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | DERIVATIVES All derivative financial instruments are recorded at fair value. 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 changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” Commodity Contracts During 2021, 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. Under the Partnership’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Partnership and when the settlement price is above the ceiling price, the Partnership is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required. The Partnership’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing) and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing. 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, 2021, 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. 2022 Collars 2,500 WTI Cushing $— $— $45.00 $79.55 $— Apr. - Jun. 2022 Collars 2,000 WTI Cushing $— $— $45.00 $80.15 $— Jul. - Sep. 2022 Collars 4,000 WTI Cushing $— $— $45.00 $92.65 $— Jan. - Mar. 2022 Puts (1) 9,500 WTI Cushing $— $— $— $— $47.51 Apr. - Jun. 2022 Puts (2) 8,000 WTI Cushing $— $— $— $— $47.50 NATURAL GAS Jan. - Dec. 2022 Collars 20,000 Henry Hub $— $— $2.50 $4.62 $— (1) Includes a deferred premium at a weighted average price of $1.57/Bbl. (2) Includes a deferred premium at a weighted average price of $1.55/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, 2021 2020 (In thousands) Gain (loss) on derivative instruments $ (69,409) $ (63,591) Net cash receipts (payments) on derivatives $ (92,585) $ (36,998) The Partnership did not have any derivatives prior to February 2020. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The 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, 2021 and December 31, 2020. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 2,340 $ — $ 2,340 $ (2,340) $ — Liabilities: Current: Derivative instruments $ — $ 28,933 $ — $ 28,933 $ (2,340) $ 26,593 Assets and Liabilities Not Recorded at Fair Value The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets: December 31, 2021 December 31, 2020 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Debt: Revolving credit facility $ 304,000 $ 304,000 $ 84,000 $ 84,000 5.375% senior notes due 2027 (1) $ 472,727 $ 498,992 $ 471,644 $ 501,439 (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, 2021 quoted market price, a Level 1 classification in the fair value hierarchy. Fair Value of Financial Assets The Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current 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, 2021 | |
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, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. These proceedings, disputes and claims may include differing interpretations as to the prices at which crude oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, title claims, environmental issues and other matters. While the ultimate outcome of the 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, 2021 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS Cash Distribution On February 16, 2022, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2021 of $0.47 per common unit, payable on March 11, 2022, to unitholders of record at the close of business on March 4, 2022. Repurchase of Units On January 13, 2022, as part of our common unit repurchase program, the Partnership repurchased 1.5 million common units with an aggregate purchase price of approximately $37.3 million in a privately negotiated transaction with an affiliate of Blackstone. This was funded through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility and was accounted for under the cost method. The common units were immediately retired. Divestiture 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 sales price of $29.3 million, subject to post-closing adjustments. |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Operations (Unaudited) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 2020 (In thousands) Oil and natural gas interests: Proved $ 1,873,418 $ 1,530,636 Unproved 1,640,172 1,364,906 Total oil and natural gas interests 3,513,590 2,895,542 Accumulated depletion and impairment (599,163) (496,176) Net oil and natural gas interests capitalized $ 2,914,427 $ 2,399,366 Costs incurred in oil and natural gas activities Costs incurred in oil and natural gas property acquisition activities are as follows: December 31, 2021 2020 2019 (In thousands) Acquisition costs: Proved properties $ 138,882 $ 9,509 $ 318,525 Unproved properties 479,041 56,169 833,221 Total $ 617,923 $ 65,678 $ 1,151,746 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 as of December 31, 2021, 2020 and 2019 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The changes in estimated proved reserves are as follows: Oil Natural Gas Liquids Natural Gas (In thousands) Proved Developed and Undeveloped Reserves: As of December 31, 2018 41,878 10,992 61,597 Purchase of reserves in place 12,949 4,895 24,423 Extensions and discoveries 11,526 3,095 14,822 Revisions of previous estimates (6,810) 1,041 2,589 Production (5,123) (1,459) (7,657) As of December 31, 2019 54,420 18,564 95,774 Purchase of reserves in place 491 113 507 Extensions and discoveries 15,415 4,424 23,982 Revisions of previous estimates (6,685) 763 11,043 Divestitures (155) (63) (370) Production (5,956) (1,848) (11,486) As of December 31, 2020 57,530 21,953 119,450 Purchase of reserves in place 5,246 2,264 9,549 Extensions and discoveries 17,256 7,182 39,256 Revisions of previous estimates (4,544) (1,339) 29,788 Divestitures (180) (114) (681) Production (6,068) (1,913) (13,672) As of December 31, 2021 69,240 28,033 183,690 Proved Developed Reserves: December 31, 2019 40,857 14,994 80,737 December 31, 2020 40,220 16,724 93,617 December 31, 2021 49,280 19,476 134,485 Proved Undeveloped Reserves: December 31, 2019 13,563 3,570 15,037 December 31, 2020 17,310 5,229 25,833 December 31, 2021 19,960 8,557 49,205 Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. During the year ended December 31, 2021, the 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. During the year ended December 31, 2019, the Partnership’s extensions and discoveries of 17,091 MBOE resulted primarily from the drilling of 829 new wells and from 97 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 5,337 MBOE were primarily due to proved undeveloped reserves downgrades and realized prices, which were partially offset by extensions and performance . The purchase of reserves in place of 21,914 MBOE were due to multiple acquisitions , primarily the Drop-Down transaction from Diamondback and the acquisition of certain mineral and royalty interests from Santa Elena Minerals, LP. 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, 2021, 2020 and 2019: December 31, 2021 2020 2019 (In thousands) Future cash inflows $ 5,763,433 $ 2,460,052 $ 3,218,257 Future production taxes (416,761) (181,067) (237,181) Future income tax expense (572,991) (22,993) (150,373) Future net cash flows 4,773,681 2,255,992 2,830,703 10% discount to reflect timing of cash flows (2,680,564) (1,232,398) (1,512,315) Standardized measure of discounted future net cash flows $ 2,093,117 $ 1,023,594 $ 1,318,388 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, 2021 2020 2019 Oil (per Bbl) $ 64.87 $ 37.61 $ 52.86 Natural gas (per Mcf) $ 2.97 $ 0.34 $ 0.51 Natural gas liquids (per Bbl) $ 25.93 $ 11.65 $ 15.79 Principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves are as follows: December 31, 2021 2020 2019 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 1,023,594 $ 1,318,388 $ 1,139,382 Purchase of minerals in place 170,205 10,781 339,814 Divestiture of reserves (4,402) (3,481) — Sales of oil and natural gas, net of production costs (468,976) (227,137) (274,735) Extensions and discoveries 615,762 280,486 330,097 Net changes in prices and production costs 863,458 (465,582) (301,182) Revisions of previous quantity estimates 45,788 (87,614) (114,409) Net changes in income taxes (243,186) 59,754 56,502 Accretion of discount 103,446 138,901 126,650 Net changes in timing of production and other (12,572) (902) 16,269 Standardized measure of discounted future net cash flows at the end of the period $ 2,093,117 $ 1,023,594 $ 1,318,388 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The 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, in 2020, the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressure in the first half of 2020, followed by a recovery in pricing and an increase in demand in the second half of 2020 and into 2021. However, the COVID-19 Delta variant emerged in March 2021 and became highly transmissible in July 2021, and the Omicron variant emerged in November 2021, which contributed to additional pricing volatility during the fourth quarter of 2021. 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 the particular circumstances. 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, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the 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. |
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. |
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. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. 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. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. 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, 2021 and 2020, 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 $10.04, $10.34 and $9.95 for the years ended December 31, 2021, 2020 and 2019, respectively. Depletion for oil and natural gas properties was $103.0 million, $100.5 million and $78.2 million for the years ended December 31, 2021, 2020 and 2019, 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 on an annual basis 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 $9.6 million and $6.7 million, and accumulated amortization of those costs over the term of the credit agreement of $6.8 million and $4.4 million as of December 31, 2021, and 2020, 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 interest revenue in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2021, three purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (17%), Shell Trading (US) Company (“Shell Trading”) (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 (13%) and Concho Resources (11%). For the year ended December 31, 2019, three purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (27%), Concho Resources (16%) and Shell Trading (12%). 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. 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, 2021, 2020 and 2019, there was no |
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 Partnership Distributions for further discussion of the change in ownership. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Recently Adopted Pronouncements In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”. This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted There are no recent 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, 2021 | |
Accounting Policies [Abstract] | |
Schedule of Accrued Liabilities | Accrued liabilities consist of the following: December 31, 2021 2020 (In thousands) Interest payable $ 4,430 $ 4,311 Ad valorem taxes payable 6,201 6,501 Derivatives instruments payable 8,879 7,392 Other 1,470 58 Total accrued liabilities $ 20,980 $ 18,262 |
Revenue From Contracts With C_2
Revenue From Contracts With Customers (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table disaggregates the Partnership’s total royalty income by product type: Year Ended December 31, 2021 2020 2019 (In thousands) Oil income $ 397,513 $ 217,859 $ 264,376 Natural gas income 49,197 9,024 8,092 Natural gas liquids income 54,824 20,098 21,343 Total royalty income $ 501,534 $ 246,981 $ 293,811 |
Oil and Natural Gas Interests (
Oil and Natural Gas Interests (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 2020 (In thousands) Oil and natural gas interests: Subject to depletion $ 1,873,418 $ 1,530,636 Not subject to depletion 1,640,172 1,364,906 Gross oil and natural gas interests 3,513,590 2,895,542 Accumulated depletion and impairment (599,163) (496,176) Oil and natural gas interests, net 2,914,427 2,399,366 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 2,920,115 $ 2,405,054 Balance of costs not subject to depletion: Incurred in 2021 $ 478,747 Incurred in 2020 55,041 Incurred in 2019 827,680 Incurred in 2018 278,704 Total not subject to depletion $ 1,640,172 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2021 2020 (In thousands) Oil and natural gas interests: Proved $ 1,873,418 $ 1,530,636 Unproved 1,640,172 1,364,906 Total oil and natural gas interests 3,513,590 2,895,542 Accumulated depletion and impairment (599,163) (496,176) Net oil and natural gas interests capitalized $ 2,914,427 $ 2,399,366 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Schedule of Maturities of Long-Term Debt | Long-term debt consisted of the following as of the dates indicated: December 31, 2021 2020 (In thousands) 5.375% senior unsecured notes due 2027 $ 479,938 $ 479,938 Revolving credit facility 304,000 84,000 Unamortized debt issuance costs (1,757) (2,058) Unamortized discount (5,454) (6,236) Total long-term debt $ 776,727 $ 555,644 |
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, 2021 | |
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, 2021 2020 2019 (In thousands) Net income (loss) attributable to the Partnership $ 57,939 $ (192,304) $ 46,281 Change in ownership of consolidated subsidiaries (93,473) (34,087) (15,054) Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest $ (35,534) $ (226,391) $ 31,227 |
Distributions Made to Limited Partner, by Distribution | The following table presents cash distributions approved by the board of directors of the General Partner for the periods presented: Distributions (In thousands) Period Amount per Unit Percentage of Operating Company Available Cash Distributed Operating Company Distributions to Diamondback Common Unitholders (1) Declaration Date Unitholder Record Date Payment Date Q4 2018 $ 0.51 100 % $ 36,934 $ 26,382 January 30, 2019 February 19, 2019 February 25, 2019 Q1 2019 $ 0.38 100 % $ 27,519 $ 23,839 April 25, 2019 May 13, 2019 May 20, 2019 Q2 2019 $ 0.47 100 % $ 34,036 $ 29,483 July 28, 2019 August 14, 2019 August 21, 2019 Q3 2019 $ 0.46 100 % $ 33,312 $ 28,639 October 25, 2019 November 8, 2019 November 15, 2019 Q4 2019 $ 0.45 100 % $ 40,819 $ 30,543 February 7, 2020 February 21, 2020 February 28, 2020 Q1 2020 $ 0.10 25 % $ 9,074 $ 6,790 April 30, 2020 May 14, 2020 May 21, 2020 Q2 2020 $ 0.03 25 % $ 2,720 $ 2,034 July 29, 2020 August 13, 2020 August 20, 2020 Q3 2020 $ 0.10 50 % $ 9,072 $ 6,805 October 28, 2020 November 12, 2020 November 19, 2020 Q4 2020 $ 0.14 50 % $ 12,699 $ 9,162 February 19, 2021 March 4, 2021 March 11, 2021 Q1 2021 $ 0.25 60 % $ 22,678 $ 16,230 April 27, 2021 May 13, 2021 May 20, 2021 Q2 2021 $ 0.33 70 % $ 29,936 $ 21,235 July 28, 2021 August 12, 2021 August 19, 2021 Q3 2021 $ 0.38 70 % $ 34,469 $ 30,118 October 27, 2021 November 11, 2021 November 18, 2021 (1) Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback. |
Earnings Per Common Unit (Table
Earnings Per Common Unit (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 2020 2019 (In thousands, except per unit amounts) Net income (loss) attributable to the period $ 57,939 $ (192,304) $ 46,281 Less: net income (loss) allocated to participating securities (1) 193 (44) (117) Net income (loss) attributable to common unitholders $ 58,132 $ (192,348) $ 46,164 Weighted average common units outstanding: Basic weighted average common units outstanding 68,319 67,686 61,744 Effect of dilutive securities: Potential common units issuable (2) 72 — 43 Diluted weighted average common units outstanding 68,391 67,686 61,787 Net income (loss) per common unit, basic $ 0.85 $ (2.84) $ 0.75 Net income (loss) per common unit, diluted $ 0.85 $ (2.84) $ 0.75 (1) Distribution equivalent rights granted to employees are considered participating securities. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021, 2020 and 2019 are as follows: Year Ended December 31, 2021 2020 2019 (In thousands) Current income tax provision (benefit): Federal $ 1,218 $ — $ — State 303 — — Total current income tax provision (benefit) 1,521 — — Deferred income tax provision (benefit): Federal — 142,466 (41,582) State — — — Total deferred income tax provision (benefit) — 142,466 (41,582) Total provision (benefit) from income taxes $ 1,521 $ 142,466 $ (41,582) Effective tax rates 0.6 % (279.6) % (23.1) % |
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, 2021 2020 2019 (In thousands) Income tax expense (benefit) at the federal statutory rate (21%) $ 54,221 $ (10,699) $ 37,722 Impact of nontaxable noncontrolling interest (41,735) 233 (36,735) State income tax expense (benefit), net of federal tax effect 262 — — Deferred taxes related to change in tax status — — (42,424) Change in valuation allowance (11,175) 152,898 — Other, net (52) 34 (145) Provision for (benefit from) income taxes $ 1,521 $ 142,466 $ (41,582) |
Schedule of Deferred Tax Assets and Liabilities | The components of the Partnership’s deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows: Year Ended December 31, 2021 2020 (In thousands) Deferred tax assets: Net operating loss and interest expense carryforwards (indefinite life carryforward) $ 6,014 $ 10,477 Investment in the Operating Company 163,065 150,127 Total deferred tax assets 169,079 160,604 Valuation allowance (169,079) (160,604) Net deferred tax assets — — Net deferred tax assets (liabilities) $ — $ — |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments | As of December 31, 2021, the 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. 2022 Collars 2,500 WTI Cushing $— $— $45.00 $79.55 $— Apr. - Jun. 2022 Collars 2,000 WTI Cushing $— $— $45.00 $80.15 $— Jul. - Sep. 2022 Collars 4,000 WTI Cushing $— $— $45.00 $92.65 $— Jan. - Mar. 2022 Puts (1) 9,500 WTI Cushing $— $— $— $— $47.51 Apr. - Jun. 2022 Puts (2) 8,000 WTI Cushing $— $— $— $— $47.50 NATURAL GAS Jan. - Dec. 2022 Collars 20,000 Henry Hub $— $— $2.50 $4.62 $— (1) Includes a deferred premium at a weighted average price of $1.57/Bbl. (2) Includes a deferred premium at a weighted average price of $1.55/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, 2021 2020 (In thousands) Gain (loss) on derivative instruments $ (69,409) $ (63,591) Net cash receipts (payments) on derivatives $ (92,585) $ (36,998) The Partnership did not have any derivatives prior to February 2020. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 and December 31, 2020. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 2,340 $ — $ 2,340 $ (2,340) $ — Liabilities: Current: Derivative instruments $ — $ 28,933 $ — $ 28,933 $ (2,340) $ 26,593 |
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, 2021 and December 31, 2020. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 2,340 $ — $ 2,340 $ (2,340) $ — Liabilities: Current: Derivative instruments $ — $ 28,933 $ — $ 28,933 $ (2,340) $ 26,593 |
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, 2021 and December 31, 2020. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. As of December 31, 2021 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 1,921 $ — $ 1,921 $ (1,921) $ — Liabilities: Current: Derivative instruments $ — $ 5,338 $ — $ 5,338 $ (1,921) $ 3,417 As of December 31, 2020 Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet (In thousands) Assets: Current: Derivative instruments $ — $ 2,340 $ — $ 2,340 $ (2,340) $ — Liabilities: Current: Derivative instruments $ — $ 28,933 $ — $ 28,933 $ (2,340) $ 26,593 |
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, 2021 December 31, 2020 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Debt: Revolving credit facility $ 304,000 $ 304,000 $ 84,000 $ 84,000 5.375% senior notes due 2027 (1) $ 472,727 $ 498,992 $ 471,644 $ 501,439 (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, 2021 | |
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, 2021 2020 (In thousands) Oil and natural gas interests: Subject to depletion $ 1,873,418 $ 1,530,636 Not subject to depletion 1,640,172 1,364,906 Gross oil and natural gas interests 3,513,590 2,895,542 Accumulated depletion and impairment (599,163) (496,176) Oil and natural gas interests, net 2,914,427 2,399,366 Land 5,688 5,688 Property, net of accumulated depletion and impairment $ 2,920,115 $ 2,405,054 Balance of costs not subject to depletion: Incurred in 2021 $ 478,747 Incurred in 2020 55,041 Incurred in 2019 827,680 Incurred in 2018 278,704 Total not subject to depletion $ 1,640,172 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2021 2020 (In thousands) Oil and natural gas interests: Proved $ 1,873,418 $ 1,530,636 Unproved 1,640,172 1,364,906 Total oil and natural gas interests 3,513,590 2,895,542 Accumulated depletion and impairment (599,163) (496,176) Net oil and natural gas interests capitalized $ 2,914,427 $ 2,399,366 |
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, 2021 2020 2019 (In thousands) Acquisition costs: Proved properties $ 138,882 $ 9,509 $ 318,525 Unproved properties 479,041 56,169 833,221 Total $ 617,923 $ 65,678 $ 1,151,746 |
Schedule of Changes in Estimated Proved Reserves | The changes in estimated proved reserves are as follows: Oil Natural Gas Liquids Natural Gas (In thousands) Proved Developed and Undeveloped Reserves: As of December 31, 2018 41,878 10,992 61,597 Purchase of reserves in place 12,949 4,895 24,423 Extensions and discoveries 11,526 3,095 14,822 Revisions of previous estimates (6,810) 1,041 2,589 Production (5,123) (1,459) (7,657) As of December 31, 2019 54,420 18,564 95,774 Purchase of reserves in place 491 113 507 Extensions and discoveries 15,415 4,424 23,982 Revisions of previous estimates (6,685) 763 11,043 Divestitures (155) (63) (370) Production (5,956) (1,848) (11,486) As of December 31, 2020 57,530 21,953 119,450 Purchase of reserves in place 5,246 2,264 9,549 Extensions and discoveries 17,256 7,182 39,256 Revisions of previous estimates (4,544) (1,339) 29,788 Divestitures (180) (114) (681) Production (6,068) (1,913) (13,672) As of December 31, 2021 69,240 28,033 183,690 Proved Developed Reserves: December 31, 2019 40,857 14,994 80,737 December 31, 2020 40,220 16,724 93,617 December 31, 2021 49,280 19,476 134,485 Proved Undeveloped Reserves: December 31, 2019 13,563 3,570 15,037 December 31, 2020 17,310 5,229 25,833 December 31, 2021 19,960 8,557 49,205 |
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, 2021, 2020 and 2019: December 31, 2021 2020 2019 (In thousands) Future cash inflows $ 5,763,433 $ 2,460,052 $ 3,218,257 Future production taxes (416,761) (181,067) (237,181) Future income tax expense (572,991) (22,993) (150,373) Future net cash flows 4,773,681 2,255,992 2,830,703 10% discount to reflect timing of cash flows (2,680,564) (1,232,398) (1,512,315) Standardized measure of discounted future net cash flows $ 2,093,117 $ 1,023,594 $ 1,318,388 |
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, 2021 2020 2019 Oil (per Bbl) $ 64.87 $ 37.61 $ 52.86 Natural gas (per Mcf) $ 2.97 $ 0.34 $ 0.51 Natural gas liquids (per Bbl) $ 25.93 $ 11.65 $ 15.79 |
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, 2021 2020 2019 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 1,023,594 $ 1,318,388 $ 1,139,382 Purchase of minerals in place 170,205 10,781 339,814 Divestiture of reserves (4,402) (3,481) — Sales of oil and natural gas, net of production costs (468,976) (227,137) (274,735) Extensions and discoveries 615,762 280,486 330,097 Net changes in prices and production costs 863,458 (465,582) (301,182) Revisions of previous quantity estimates 45,788 (87,614) (114,409) Net changes in income taxes (243,186) 59,754 56,502 Accretion of discount 103,446 138,901 126,650 Net changes in timing of production and other (12,572) (902) 16,269 Standardized measure of discounted future net cash flows at the end of the period $ 2,093,117 $ 1,023,594 $ 1,318,388 |
Organization and Basis of Pre_2
Organization and Basis of Presentation (Details) - Diamondback Energy, Inc. - Viper Energy Partners LP | 12 Months Ended |
Dec. 31, 2021 | |
Limited Partners' Capital Account [Line Items] | |
Percent of general partner interest | 100.00% |
Percent of limited partnership interest | 54.00% |
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, 2021USD ($)$ / Boe | Dec. 31, 2020USD ($)$ / Boe | Dec. 31, 2019USD ($)$ / Boe | |
Debt Instrument [Line Items] | |||
Average depletion rate per barrel equivalent unit of production | $ / Boe | 10.04 | 10.34 | 9.95 |
Depletion for oil and natural gas properties | $ 102,987 | $ 100,501 | $ 78,178 |
Debt issuance costs, net of accumulated amortizations | 9,600 | 6,700 | |
Debit issuance costs, accumulated amortization | $ 6,800 | $ 4,400 | |
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 - Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Interest payable | $ 4,430 | $ 4,311 |
Ad valorem taxes payable | 6,201 | 6,501 |
Derivatives instruments payable | 8,879 | 7,392 |
Other | 1,470 | 58 |
Total accrued liabilities | $ 20,980 | $ 18,262 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Concentrations (Details) - Customer Concentration Risk - Royalty Interest Revenue | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Trafigura Trading LLC | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 17.00% | 23.00% | 27.00% |
Shell Trading | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 16.00% | 13.00% | 12.00% |
Vitol Midstream Pipeline LLC | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 12.00% | 14.00% | |
Concho Resources, Inc | |||
Concentration Risk [Line Items] | |||
Percent of total royalty interest revenue | 11.00% | 16.00% |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Accounting Policies [Abstract] | |||
Interest or penalties associated with uncertain tax positions | $ 0 | $ 0 | $ 0 |
Revenue From Contracts With C_3
Revenue From Contracts With Customers (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Disaggregation of Revenue [Line Items] | |||
Total royalty income | $ 501,534 | $ 246,981 | $ 293,811 |
Oil income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | 397,513 | 217,859 | 264,376 |
Natural gas income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | 49,197 | 9,024 | 8,092 |
Natural gas liquids income | |||
Disaggregation of Revenue [Line Items] | |||
Total royalty income | $ 54,824 | $ 20,098 | $ 21,343 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - 2021 Activity (Details) shares in Thousands, $ in Millions | Oct. 01, 2021USD ($)ashares | Aug. 01, 2021USD ($) | Dec. 31, 2021USD ($)a |
Swallowtail Acquisition | |||
Asset Acquisition [Line Items] | |||
Number of shares issued (in shares) | shares | 15,250 | ||
Payments for asset acquisitions | $ 225.3 | ||
Percentage of shares acquired | 62.00% | ||
Contingent consideration | $ 30 | ||
Payment of contingent consideration | $ 190 | ||
Swallowtail Acquisition | Northern Midland Basin | |||
Asset Acquisition [Line Items] | |||
Net royalty (acres) | a | 2,313 | ||
Other 2021 Acquisitions | |||
Asset Acquisition [Line Items] | |||
Net royalty (acres) | a | 392 | ||
Gross acres (acres) | a | 1,277 | ||
Aggregate purchase price | $ 55.1 |
Acquisitions and Divestitures_2
Acquisitions and Divestitures - 2020 Acquisitions (Details) - 2020 Acquisitions $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($)a | |
Asset Acquisition [Line Items] | |
Gross acres (acres) | 4,948 |
Net royalty (acres) | 417 |
Aggregate purchase price | $ | $ 64.2 |
Acquisitions and Divestitures_3
Acquisitions and Divestitures - 2019 Activity (Details) shares in Millions, $ in Millions | Dec. 31, 2019USD ($)a | Oct. 31, 2019USD ($)ashares | Oct. 01, 2019USD ($)ashares |
Drop-Down Acquisition | |||
Asset Acquisition [Line Items] | |||
Fair value consideration of units issued in acquisition | $ | $ 497.2 | ||
Payments for asset acquisitions | $ | $ 190.2 | ||
Net royalty (acres) | a | 5,490 | ||
Percentage of mineral acres operated | 95.00% | ||
Percentage of average net royalty interest in acquired mineral and royalty interests | 3.20% | ||
Drop-Down Acquisition | Class B Units | |||
Asset Acquisition [Line Items] | |||
Number of shares issued (in shares) | shares | 18.3 | ||
Santa Elena Acquisition | |||
Asset Acquisition [Line Items] | |||
Fair value consideration of units issued in acquisition | $ | $ 124 | ||
Net royalty (acres) | a | 1,366 | ||
Percentage of average net royalty interest in acquired mineral and royalty interests | 5.60% | ||
Santa Elena Acquisition | Limited Partners | |||
Asset Acquisition [Line Items] | |||
Number of shares issued (in shares) | shares | 5.2 | ||
Other 2019 Acquisitions | |||
Asset Acquisition [Line Items] | |||
Net royalty (acres) | a | 2,607 | ||
Gross acres (acres) | a | 136,012 | ||
Aggregate purchase price | $ | $ 343.7 |
Acquisitions and Divestitures_4
Acquisitions and Divestitures - Divestiture of Certain Non-Core Assets and Investments (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($)a | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Proceeds from sale of equity interest | $ 10.8 |
Non-Core Permian Assets | Discontinued Operations, Disposed of by Sale | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Area of land | a | 370 |
Consideration from sale | $ 38.4 |
Oil and Natural Gas Interests_2
Oil and Natural Gas Interests (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2021USD ($)a | Dec. 31, 2020USD ($)a | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Property, Plant and Equipment [Line Items] | ||||
Subject to depletion | $ 1,873,418 | $ 1,530,636 | ||
Not subject to depletion | 1,640,172 | 1,364,906 | ||
Gross oil and natural gas interests | 3,513,590 | 2,895,542 | ||
Accumulated depletion and impairment | (599,163) | (496,176) | ||
Oil and natural gas interests, net | 2,914,427 | 2,399,366 | ||
Land | 5,688 | 5,688 | ||
Property, net | 2,920,115 | 2,405,054 | ||
Balance of costs not subject to depletion: | $ 478,747 | $ 55,041 | $ 827,680 | $ 278,704 |
Net royalty acres | a | 27,027 | 24,350 | ||
Impairment | $ 0 | $ 69,202 | $ 0 | |
Minimum | ||||
Property, Plant and Equipment [Line Items] | ||||
Anticipated timing of cost inclusion in amortization calculation | 5 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, 2021 | Dec. 31, 2020 |
Line of Credit Facility [Line Items] | ||
Unamortized debt issuance costs | $ (1,757) | $ (2,058) |
Unamortized discount | (5,454) | (6,236) |
Long-term debt, net | 776,727 | 555,644 |
Revolving credit facility | Line of Credit | ||
Line of Credit Facility [Line Items] | ||
Long term debt gross | 304,000 | 84,000 |
5.375% senior unsecured notes due 2027 | Senior Notes | ||
Line of Credit Facility [Line Items] | ||
Long term debt gross | $ 479,938 | $ 479,938 |
Debt instrument, interest rate, stated percentage | 5.375% |
Debt - Additional Information (
Debt - Additional Information (Details) | 12 Months Ended | ||||
Dec. 31, 2021USD ($) | Dec. 31, 2020 | Dec. 31, 2019 | Nov. 15, 2021USD ($) | Jun. 02, 2021 | |
Senior Notes | |||||
Line of Credit Facility [Line Items] | |||||
Maximum issuance of unsecured debt | $ 1,000,000,000 | ||||
Reduction of borrowing base | 25.00% | ||||
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 | 304,000,000 | ||||
Remaining borrowing capacity | $ 196,000,000 | ||||
Weighted average interest rate | 2.35% | 2.20% | 4.51% | ||
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 | 1.00% | ||||
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 | 2.00% | ||||
Minimum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | Base Rate | |||||
Line of Credit Facility [Line Items] | |||||
Debt instrument applicable margin | 1.00% | ||||
Maximum | Operating Company Revolving Credit Facility | |||||
Line of Credit Facility [Line Items] | |||||
Ratio of secured debt to EBITDAX, as defined in the credit agreement | 2.5 | 2.50 | |||
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 | 3.00% | ||||
Maximum | Operating Company Revolving Credit Facility | Line of Credit | Revolving Credit Facility | Base Rate | |||||
Line of Credit Facility [Line Items] | |||||
Debt instrument applicable margin | 2.00% |
Debt - Financial Covenants (Det
Debt - Financial Covenants (Details) - Operating Company Revolving Credit Facility | Dec. 31, 2021 | Jun. 02, 2021 |
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 | 2.50 |
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, 2021 | Dec. 31, 2020 | Feb. 18, 2022 | Nov. 15, 2021 | |
Limited Partners' Capital Account [Line Items] | ||||
Amount of shares repurchased | $ 45,999,000 | $ 24,026,000 | ||
Special allocation, shortened period | 1 year | |||
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] | ||||
Authorized amount in repurchase program | $ 100,000,000 | $ 150,000,000 | ||
Amount of shares repurchased | 46,000,000 | $ 24,000,000 | ||
Remaining authorized repurchase amount | $ 80,000,000 | |||
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 | 54.00% | |||
Percentage by noncontrolling owners | 54.00% | |||
Common Units | ||||
Limited Partners' Capital Account [Line Items] | ||||
Limited partners' capital account, units issued (in shares) | 78,546,403 | 65,817,281 | ||
Limited partners' capital account, units outstanding (in shares) | 78,546,403 | 65,817,281 | ||
Shares issued (in shares) | 1 | |||
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Net income (loss) attributable to the Partnership | $ 57,939 | $ (192,304) | $ 46,281 |
Limited Partners | |||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | |||
Net income (loss) attributable to the Partnership | 57,939 | (192,304) | 46,281 |
Change in ownership of consolidated subsidiaries | (93,473) | (34,087) | (15,054) |
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest | $ (35,534) | $ (226,391) | $ 31,227 |
Unitholders_ Equity and Distr_5
Unitholders’ Equity and Distributions - Schedule of Partnership Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands | Oct. 27, 2021 | Jul. 28, 2021 | Apr. 27, 2021 | Feb. 19, 2021 | Oct. 28, 2020 | Jul. 29, 2020 | Apr. 30, 2020 | Feb. 07, 2020 | Oct. 25, 2019 | Jul. 28, 2019 | Apr. 25, 2019 | Jan. 30, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Distributions | $ 75,749 | $ 45,630 | $ 107,074 | ||||||||||||
Cash Distribution | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Cash distribution, amount per Common Unit (in USD per share) | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | $ 0.10 | $ 0.03 | $ 0.10 | $ 0.45 | $ 0.46 | $ 0.47 | $ 0.38 | $ 0.51 | |||
Cash Distribution | Operating Company Units | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Percentage of Operating Company Available Cash Distributed | 70.00% | 70.00% | 60.00% | 50.00% | 50.00% | 25.00% | 25.00% | 100.00% | 100.00% | 100.00% | 100.00% | 100.00% | |||
Distributions | $ 34,469 | $ 29,936 | $ 22,678 | $ 12,699 | $ 9,072 | $ 2,720 | $ 9,074 | $ 40,819 | $ 33,312 | $ 34,036 | $ 27,519 | $ 36,934 | |||
Cash Distribution | Common Units | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Distributions | $ 30,118 | $ 21,235 | $ 16,230 | $ 9,162 | $ 6,805 | $ 2,034 | $ 6,790 | $ 30,543 | $ 28,639 | $ 29,483 | $ 23,839 | $ 26,382 |
Earnings Per Common Unit (Detai
Earnings Per Common Unit (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |||
Net income (loss) attributable to the period | $ 57,939 | $ (192,304) | $ 46,281 |
Less: net income (loss) allocated to participating securities | 193 | (44) | (117) |
Net income (loss) attributable to common unitholders | $ 58,132 | $ (192,348) | $ 46,164 |
Basic weighted average common units outstanding (in shares) | 68,319,000 | 67,686,000 | 61,744,000 |
Effect of dilutive securities: | |||
Potential common units issuable (in shares) | 72,000 | 0 | 43,000 |
Diluted weighted average common units outstanding (in shares) | 68,391,000 | 67,686,000 | 61,787,000 |
Net income per common unit, basic (dollars per shares) | $ 0.85 | $ (2.84) | $ 0.75 |
Net income per common unit, diluted (dollars per shares) | $ 0.85 | $ (2.84) | $ 0.75 |
Antidilutive securities, restricted stock units (in shares) | 10,160 | 0 |
Income Taxes - Components of Pr
Income Taxes - Components of Provision for Income Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current income tax provision (benefit): | |||
Federal | $ 1,218,000 | $ 0 | $ 0 |
State | 303,000 | 0 | 0 |
Total current income tax provision (benefit) | 1,521,000 | 0 | 0 |
Deferred income tax provision (benefit): | |||
Federal | 0 | 142,466,000 | (41,582,000) |
State | 0 | 0 | 0 |
Total deferred income tax provision (benefit) | 0 | 142,466,000 | (41,582,000) |
Total provision (benefit) from income taxes | $ 1,521,000 | $ 142,466,000 | $ (41,582,000) |
Effective tax rates | 0.60% | (279.60%) | (23.10%) |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Statutory Federal Income tax (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense (benefit) at the federal statutory rate (21%) | $ 54,221 | $ (10,699) | $ 37,722 |
Impact of nontaxable noncontrolling interest | (41,735) | 233 | (36,735) |
State income tax expense (benefit), net of federal tax effect | 262 | 0 | 0 |
Deferred taxes related to change in tax status | 0 | 0 | (42,424) |
Change in valuation allowance | (11,175) | 152,898 | 0 |
Other, net | (52) | 34 | (145) |
Total provision (benefit) from income taxes | $ 1,521 | $ 142,466 | $ (41,582) |
Income Taxes - Deferred Tax Ass
Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 |
Deferred tax assets: | ||
Net operating loss and interest expense carryforwards (indefinite life carryforward) | $ 6,014,000 | $ 10,477,000 |
Investment in the Operating Company | 163,065,000 | 150,127,000 |
Total deferred tax assets | 169,079,000 | 160,604,000 |
Valuation allowance | (169,079,000) | (160,604,000) |
Net deferred tax assets | 0 | 0 |
Net deferred tax assets (liabilities) | $ 0 | $ 0 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Net deferred tax assets | $ 0 | $ 0 | |
Net deferred tax liabilities | 0 | 0 | |
Federal net operating loss carryforwards | 28,600,000 | ||
Valuation allowance | 169,079,000 | 160,604,000 | |
State income tax expense | $ 303,000 | $ 0 | $ 0 |
Derivatives - Open Derivative P
Derivatives - Open Derivative Positions (Details) - 2022 | 12 Months Ended |
Dec. 31, 2021$ / bblbbl | |
Apr. - Jun. | WTI Cushing | Puts | |
Derivative [Line Items] | |
Deferred Premium Weighted Average Price | 1.57 |
Jan. - Dec. | WTI Cushing | Puts | |
Derivative [Line Items] | |
Deferred Premium Weighted Average Price | 1.55 |
OIL | Jan. - Mar. | WTI Cushing | Collars | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 2,500 |
Weighted Average Differential | 0 |
Weighted Average Fixed Price | 0 |
Floor price (per Bbl) | 45 |
Ceiling price (per Bbl) | 79.55 |
Strike price (USD per bbl) | 0 |
OIL | Jan. - Mar. | WTI Cushing | Puts | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 9,500 |
Weighted Average Differential | 0 |
Weighted Average Fixed Price | 0 |
Floor price (per Bbl) | 0 |
Ceiling price (per Bbl) | 0 |
Strike price (USD per bbl) | 47.51 |
OIL | Apr. - Jun. | WTI Cushing | Collars | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 2,000 |
Weighted Average Differential | 0 |
Weighted Average Fixed Price | 0 |
Floor price (per Bbl) | 45 |
Ceiling price (per Bbl) | 80.15 |
Strike price (USD per bbl) | 0 |
OIL | Apr. - Jun. | WTI Cushing | Puts | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 8,000 |
Weighted Average Differential | 0 |
Weighted Average Fixed Price | 0 |
Floor price (per Bbl) | 0 |
Ceiling price (per Bbl) | 0 |
Strike price (USD per bbl) | 47.50 |
OIL | Jul. - Sep. | WTI Cushing | Collars | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 4,000 |
Weighted Average Differential | 0 |
Weighted Average Fixed Price | 0 |
Floor price (per Bbl) | 45 |
Ceiling price (per Bbl) | 92.65 |
Strike price (USD per bbl) | 0 |
NATURAL GAS | Jan. - Dec. | Henry Hub | Collars | |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 20,000 |
Weighted Average Differential | 0 |
Weighted Average Fixed Price | 0 |
Floor price (per Bbl) | 2.50 |
Ceiling price (per Bbl) | 4.62 |
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Gain (loss) on derivative instruments | $ (69,409) | $ (63,591) | $ 0 |
Net cash receipts (payments) on derivatives | $ (92,585) | $ (36,998) | $ 0 |
Fair Value Measurements - Recur
Fair Value Measurements - Recurring Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Current: | ||
Net Fair Value Presented in Balance Sheet | $ 3,417 | $ 26,593 |
Fair Value, Recurring | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 1,921 | 2,340 |
Gross Amounts Offset in Balance Sheet | (1,921) | (2,340) |
Net Fair Value Presented in Balance Sheet | 0 | 0 |
Current: | ||
Total Gross Fair Value | 5,338 | 28,933 |
Gross Amounts Offset in Balance Sheet | (1,921) | (2,340) |
Net Fair Value Presented in Balance Sheet | 3,417 | 26,593 |
Fair Value, Recurring | Level 1 | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 0 | 0 |
Current: | ||
Total Gross Fair Value | 0 | 0 |
Fair Value, Recurring | Level 2 | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 1,921 | 2,340 |
Current: | ||
Total Gross Fair Value | 5,338 | 28,933 |
Fair Value, Recurring | Level 3 | Derivative instruments | ||
Current: | ||
Total Gross Fair Value | 0 | 0 |
Current: | ||
Total Gross Fair Value | $ 0 | $ 0 |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Value of Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
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 | $ 304,000 | $ 84,000 |
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 | 472,727 | 471,644 |
Fair Value | Fair Value, Nonrecurring | Revolving credit facility | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, fair value | 304,000 | 84,000 |
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 | $ 498,992 | $ 501,439 |
Subsequent Events (Details)
Subsequent Events (Details) $ / shares in Units, shares in Thousands, $ in Thousands | Feb. 16, 2022$ / shares | Jan. 13, 2022USD ($)shares | Oct. 27, 2021$ / shares | Jul. 28, 2021$ / shares | Apr. 27, 2021$ / shares | Feb. 19, 2021$ / shares | Oct. 28, 2020$ / shares | Jul. 29, 2020$ / shares | Apr. 30, 2020$ / shares | Feb. 07, 2020$ / shares | Oct. 25, 2019$ / shares | Jul. 28, 2019$ / shares | Apr. 25, 2019$ / shares | Jan. 30, 2019$ / shares | Mar. 31, 2022USD ($)a | Dec. 31, 2021USD ($)shares | Dec. 31, 2020USD ($) |
Subsequent Event [Line Items] | |||||||||||||||||
Amount of shares repurchased | $ 45,999 | $ 24,026 | |||||||||||||||
Common Units | |||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||
Repurchased units (in shares) | shares | 2,613 | ||||||||||||||||
Amount of shares repurchased | $ 45,999 | ||||||||||||||||
Subsequent Event | Discontinued Operations, Disposed of by Sale | Third Party Operated Acreage | Forecast | Midland Basin | |||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||
Area of land | a | 325 | ||||||||||||||||
Proceeds from sale of acres | $ 29,300 | ||||||||||||||||
Subsequent Event | Common Units | |||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||
Repurchased units (in shares) | shares | 1,500 | ||||||||||||||||
Amount of shares repurchased | $ 37,300 | ||||||||||||||||
Cash Distribution | |||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||
Cash distribution, amount per Common Unit (in USD per share) | $ / shares | $ 0.38 | $ 0.33 | $ 0.25 | $ 0.14 | $ 0.10 | $ 0.03 | $ 0.10 | $ 0.45 | $ 0.46 | $ 0.47 | $ 0.38 | $ 0.51 | |||||
Cash Distribution | Subsequent Event | |||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||
Cash distribution, amount per Common Unit (in USD per share) | $ / shares | $ 0.47 |
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, 2021 | Dec. 31, 2020 |
Oil and natural gas interests: | ||
Proved | $ 1,873,418 | $ 1,530,636 |
Unproved | 1,640,172 | 1,364,906 |
Total oil and natural gas interests | 3,513,590 | 2,895,542 |
Accumulated depletion and impairment | (599,163) | (496,176) |
Net oil and natural gas interests capitalized | $ 2,914,427 | $ 2,399,366 |
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract] | |||
Proved properties | $ 138,882 | $ 9,509 | $ 318,525 |
Unproved properties | 479,041 | 56,169 | 833,221 |
Total | $ 617,923 | $ 65,678 | $ 1,151,746 |
Supplemental Information on O_5
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Changes in Estimated Proved Reserves (Details) bbl in Thousands, Mcf in Thousands | 12 Months Ended | ||
Dec. 31, 2021bblMcf | Dec. 31, 2020bblMcf | Dec. 31, 2019Mcfbbl | |
Oil | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | 57,530 | 54,420 | 41,878 |
Purchase of reserves in place | 5,246 | 491 | 12,949 |
Extensions and discoveries | 17,256 | 15,415 | 11,526 |
Revisions of previous estimates | (4,544) | (6,685) | (6,810) |
Divestitures | (180) | (155) | |
Production | (6,068) | (5,956) | (5,123) |
End of period | 69,240 | 57,530 | 54,420 |
Proved developed reserves (Volume) | 49,280 | 40,220 | 40,857 |
Proved undeveloped reserve (Volume) | 19,960 | 17,310 | 13,563 |
Natural Gas Liquids | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | 21,953 | 18,564 | 10,992 |
Purchase of reserves in place | 2,264 | 113 | 4,895 |
Extensions and discoveries | 7,182 | 4,424 | 3,095 |
Revisions of previous estimates | (1,339) | 763 | 1,041 |
Divestitures | (114) | (63) | |
Production | (1,913) | (1,848) | (1,459) |
End of period | 28,033 | 21,953 | 18,564 |
Proved developed reserves (Volume) | 19,476 | 16,724 | 14,994 |
Proved undeveloped reserve (Volume) | 8,557 | 5,229 | 3,570 |
Natural Gas | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | Mcf | 119,450 | 95,774 | 61,597 |
Purchase of reserves in place | Mcf | 9,549 | 507 | 24,423 |
Extensions and discoveries | Mcf | 39,256 | 23,982 | 14,822 |
Revisions of previous estimates | Mcf | 29,788 | 11,043 | 2,589 |
Divestitures | Mcf | (681) | (370) | |
Production | Mcf | (13,672) | (11,486) | (7,657) |
End of period | Mcf | 183,690 | 119,450 | 95,774 |
Proved developed reserves (Volume) | Mcf | 134,485 | 93,617 | 80,737 |
Proved undeveloped reserve (Volume) | Mcf | 49,205 | 25,833 | 15,037 |
Supplemental Information on O_6
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Additional Information (Details) | 12 Months Ended | ||
Dec. 31, 2021Boewell | Dec. 31, 2020Boewell | Dec. 31, 2019Boewell | |
Extractive Industries [Abstract] | |||
Partnership’s extensions and discoveries (Energy) | 30,981,000 | 23,836,000 | 17,091,000 |
Oil and gas, development well drilled, net productive, number | well | 407 | 652 | 829 |
New proved undeveloped location | well | 336 | 299 | 97 |
Revision of previous estimate (Energy) | (918,000) | (4,082,000) | (5,337,000) |
MBOE of PUDs downgraded due to positive revisions | 11,263,000 | ||
MBOE of PUDs downgraded due to price and performance revision | 10,345,000 | ||
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 | ||
Purchase of reserves (Energy) | 9,102,000 | 689,000 | 21,914,000 |
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 5,763,433 | $ 2,460,052 | $ 3,218,257 | |
Future production taxes | (416,761) | (181,067) | (237,181) | |
Future income tax expense | (572,991) | (22,993) | (150,373) | |
Future net cash flows | 4,773,681 | 2,255,992 | 2,830,703 | |
10% discount to reflect timing of cash flows | (2,680,564) | (1,232,398) | (1,512,315) | |
Standardized measure of discounted future net cash flows | $ 2,093,117 | $ 1,023,594 | $ 1,318,388 | $ 1,139,382 |
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, 2021$ / bbl$ / Mcf | Dec. 31, 2020$ / bbl$ / Mcf | Dec. 31, 2019$ / Mcf$ / bbl | |
Oil | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Unweighted arithmetic average first-day-of-the-month prices | 64.87 | 37.61 | 52.86 |
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 | 2.97 | 0.34 | 0.51 |
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 | 25.93 | 11.65 | 15.79 |
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | |||
Standardized measure of discounted future net cash flows at the beginning of the period | $ 1,023,594 | $ 1,318,388 | $ 1,139,382 |
Purchase of minerals in place | 170,205 | 10,781 | 339,814 |
Divestiture of reserves | (4,402) | (3,481) | 0 |
Sales of oil and natural gas, net of production costs | (468,976) | (227,137) | (274,735) |
Extensions and discoveries | 615,762 | 280,486 | 330,097 |
Net changes in prices and production costs | 863,458 | (465,582) | (301,182) |
Revisions of previous quantity estimates | 45,788 | (87,614) | (114,409) |
Net changes in income taxes | (243,186) | 59,754 | 56,502 |
Accretion of discount | 103,446 | 138,901 | 126,650 |
Net changes in timing of production and other | (12,572) | (902) | 16,269 |
Standardized measure of discounted future net cash flows at the end of the period | $ 2,093,117 | $ 1,023,594 | $ 1,318,388 |