Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 18, 2022 | Jun. 30, 2021 | |
Document Information | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Document Transition Report | false | ||
Entity Registrant Name | Kimbell Royalty Partners, LP | ||
Entity File Number | 001-38005 | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 47-5505475 | ||
Entity Address, Address Line One | 777 Taylor Street, Suite 810 | ||
Entity Address, City or Town | Fort Worth | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 76102 | ||
City Area Code | 817 | ||
Local Phone Number | 945-9700 | ||
Title of 12(b) Security | Common Units Representing Limited Partner Interests | ||
Trading Symbol | KRP | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 630.7 | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | true | ||
Entity Ex Transition Period | true | ||
ICFR Auditor Attestation Flag | false | ||
Entity Shell Company | false | ||
Entity Central Index Key | 0001657788 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Auditor Name | GRANT THORNTON LLP | ||
Auditor Firm ID | 248 | ||
Auditor Location | Dallas, Texas | ||
Common Units | |||
Document Information | |||
Entity Common Stock, Shares Outstanding | 47,161,782 | ||
Class B | |||
Document Information | |||
Entity Common Stock, Shares Outstanding | 17,611,579 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets | ||
Cash and cash equivalents | $ 7,052,414 | $ 9,804,977 |
Oil, natural gas and NGL receivables | 35,147,145 | 17,552,756 |
Derivative assets | 166,307 | |
Accounts receivable and other current assets | 3,051,593 | 973,956 |
Total current assets | 45,417,459 | 28,331,689 |
Property and equipment, net | 1,888,247 | 1,964,660 |
Investment in affiliate (equity method) | 4,738,822 | 5,134,951 |
Oil and natural gas properties | ||
Oil and natural gas properties, using full cost method of accounting ($153,284,173 and $225,681,626 excluded from depletion at December 31, 2021 and 2020, respectively) | 1,204,395,484 | 1,149,095,232 |
Less: accumulated depreciation, depletion and impairment | (663,603,142) | (628,102,279) |
Total oil and natural gas properties, net | 540,792,342 | 520,992,953 |
Right-of-use assets, net | 2,844,997 | 3,123,454 |
Derivative assets | 1,590,501 | |
Loan origination costs, net | 4,214,484 | 5,086,486 |
Total assets | 601,486,852 | 564,634,193 |
Current liabilities | ||
Accounts payable | 811,019 | 888,735 |
Other current liabilities | 3,319,495 | 4,765,161 |
Derivative liabilities | 24,190,678 | 3,113,178 |
Total current liabilities | 28,321,192 | 8,767,074 |
Operating lease liabilities, excluding current portion | 2,561,274 | 2,848,452 |
Derivative liabilities | 4,190,776 | 3,167,685 |
Long-term debt | 217,115,911 | 171,550,142 |
Other liabilities | 447,918 | |
Total liabilities | 252,637,071 | 186,333,353 |
Commitments and contingencies (Note 15) | ||
Mezzanine equity: | ||
Series A preferred units (0 and 55,000 units issued and outstanding as of December 31, 2021 and 2020, respectively) | 42,666,102 | |
Unitholders' equity: | ||
Common units (47,162,773 units and 38,918,689 units issued and outstanding as of December 31, 2021 and 2020, respectively) | 328,717,841 | 257,593,307 |
Class B units (17,611,579 and 20,779,781 units issued and outstanding as of December 31, 2021 and 2020, respectively) | 880,579 | 1,038,989 |
Total unitholders' equity | 329,598,420 | 258,632,296 |
Noncontrolling interest | 19,251,361 | 77,002,442 |
Total equity | 348,849,781 | 335,634,738 |
Total liabilities, mezzanine equity and unitholders' equity | $ 601,486,852 | $ 564,634,193 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 |
CONSOLIDATED BALANCE SHEETS | ||
Oil and natural gas properties excluded from depletion | $ 153,284,173 | $ 225,681,626 |
Temporary equity, issued (in units) | 0 | 55,000 |
Temporary equity, outstanding (in units) | 0 | 55,000 |
Common units, issued (in units) | 47,162,773 | 38,918,689 |
Common units, outstanding (in units) | 47,162,773 | 38,918,689 |
Class B units, issued (in units) | 17,611,579 | 20,779,781 |
Class B units, outstanding (in units) | 17,611,579 | 20,779,781 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Loss on commodity derivative instruments, net | $ (42,791,909) | $ (2,450,541) | $ (1,732,321) |
Total revenues | 135,615,216 | 90,481,915 | 108,225,270 |
Costs and expenses | |||
Production and ad valorem taxes | 10,480,481 | 6,389,231 | 7,719,949 |
Depreciation and depletion expense | 36,797,881 | 47,988,796 | 52,118,367 |
Impairment of oil and natural gas properties | 0 | 251,558,557 | 169,150,255 |
Marketing and other deductions | 12,048,643 | 9,376,375 | 8,145,397 |
General and administrative expense | 26,977,519 | 25,902,496 | 22,666,601 |
Total costs and expenses | 86,304,524 | 341,215,455 | 259,800,569 |
Operating income (loss) | 49,310,692 | (250,733,540) | (151,575,299) |
Other income (expense) | |||
Equity income in affiliate | 1,119,819 | 763,988 | 80,481 |
Interest expense | (9,182,103) | (6,430,061) | (5,813,702) |
Loss on extinguishment of debt | (476,350) | ||
Other income (expense) | 1,263,566 | (100,000) | |
Net income (loss) before income taxes | 42,511,974 | (256,975,963) | (157,308,520) |
Provision for (benefit from) income taxes | 74,100 | (885,193) | 899,425 |
Net income (loss) | 42,437,874 | (256,090,770) | (158,207,945) |
Distribution and accretion on Series A preferred units | (11,249,969) | (7,810,588) | (13,878,336) |
Net income (loss) and distributions and accretion on Series A preferred units attributable to noncontrolling interests | (8,496,104) | 96,642,334 | 89,148,428 |
Distribution on Class B units | (76,780) | (91,869) | (94,429) |
Net income (loss) attributable to common units | $ 22,615,021 | $ (167,350,893) | $ (83,032,282) |
Net income (loss) attributable to common units | |||
Net income (loss) attributable to common units (basic) (in dollar per share) | $ 0.56 | $ (4.85) | $ (3.92) |
Net income (loss) attributable to common units (diluted) (in dollar per share) | $ 0.51 | $ (4.85) | $ (3.92) |
Weighted average number of common units outstanding | |||
Weighted average number of common units outstanding Basic (in units) | 40,400,907 | 34,530,398 | 21,192,714 |
Weighted average number of common units outstanding Diluted (in units) | 60,957,824 | 34,530,398 | 21,192,714 |
Oil, natural gas and NGL revenues | |||
Revenue | $ 175,088,021 | $ 92,586,685 | $ 107,480,446 |
Lease bonus and other income | |||
Revenue | $ 3,319,104 | $ 345,771 | $ 2,477,145 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY - USD ($) | Common Units | Class B Common Units | Non Controlling Interest | Total |
Unitholders' capital, beginning balance at Dec. 31, 2018 | $ 299,821,901 | $ 972,663 | $ 291,932,233 | $ 592,726,797 |
Unitholders' capital, beginning balance (in units) at Dec. 31, 2018 | 18,056,487 | 19,453,258 | ||
Increase (Decrease) in Unitholders' Capital | ||||
Conversion of Class B units to common units | $ 93,688,489 | $ (273,250) | (93,688,489) | (273,250) |
Conversion of Class B units to common units (in units) | 5,465,000 | (5,465,000) | ||
Restricted units repurchased for tax withholding | $ (46,280) | (46,280) | ||
Restricted units repurchased for tax withholding (in units) | (2,835) | |||
Class B units issued for acquisition | $ 578,467 | 207,734,725 | 208,313,192 | |
Class B units issued for acquisition (in units) | 11,569,348 | |||
Unit-based compensation | $ 7,502,678 | 7,502,678 | ||
Distributions to unitholders | (35,384,665) | (35,672,648) | (71,057,313) | |
Distribution and accretion on Series A preferred units | (6,552,484) | (7,325,852) | (13,878,336) | |
Distribution on Class B units | (94,429) | (94,429) | ||
Net loss | (76,385,369) | (81,822,576) | (158,207,945) | |
Unitholders' capital, ending balance at Dec. 31, 2019 | $ 282,549,841 | $ 1,277,880 | 281,157,393 | 564,985,114 |
Unitholders' capital, ending balance (in units) at Dec. 31, 2019 | 23,518,652 | 25,557,606 | ||
Increase (Decrease) in Unitholders' Capital | ||||
Units issued for Acquisition | $ 13,257,174 | $ 124,857 | 14,758,062 | 28,140,093 |
Units issued for Acquisition (in units) | 2,224,358 | 2,497,134 | ||
Common units issued for equity offering | $ 73,601,668 | 73,601,668 | ||
Common units issued for equity offering (in units) | 5,000,000 | |||
Conversion of Class B units to common units | $ 92,065,325 | $ (363,748) | (92,065,325) | (363,748) |
Conversion of Class B units to common units (in units) | 7,274,959 | (7,274,959) | ||
Redemption of Series A preferred units | $ (16,150,018) | (9,697,873) | (25,847,891) | |
Restricted units repurchased for tax withholding | $ (273,244) | (273,244) | ||
Restricted units repurchased for tax withholding (in units) | (29,181) | |||
Forfeiture of restricted units | $ (127,934) | (127,934) | ||
Forfeiture of restricted units (in units) | (16,737) | |||
Unit-based compensation | $ 9,535,000 | 9,535,000 | ||
Unit-based compensation (in units) | 946,638 | |||
Distributions to unitholders | $ (29,513,612) | (20,507,481) | (50,021,093) | |
Distribution and accretion on Series A preferred units | (4,946,646) | (2,863,942) | (7,810,588) | |
Distribution on Class B units | (91,869) | (91,869) | ||
Net loss | (162,312,378) | (93,778,392) | (256,090,770) | |
Unitholders' capital, ending balance at Dec. 31, 2020 | $ 257,593,307 | $ 1,038,989 | 77,002,442 | $ 335,634,738 |
Unitholders' capital, ending balance (in units) at Dec. 31, 2020 | 38,918,689 | 20,779,781 | 38,918,689 | |
Increase (Decrease) in Unitholders' Capital | ||||
Common units issued for equity offering | $ 57,522,440 | $ 57,522,440 | ||
Common units issued for equity offering (in units) | 4,312,500 | |||
Conversion of Class B units to common units | $ 40,482,756 | $ (158,410) | (40,482,756) | (158,410) |
Conversion of Class B units to common units (in units) | 3,168,202 | (3,168,202) | ||
Redemption of Series A preferred units | $ (10,753,930) | (4,229,854) | (14,983,784) | |
Restricted units repurchased for tax withholding | $ (2,064,693) | (2,064,693) | ||
Restricted units repurchased for tax withholding (in units) | (173,185) | |||
Unit-based compensation | $ 10,632,725 | 10,632,725 | ||
Unit-based compensation (in units) | 936,567 | |||
Distributions to unitholders | $ (47,309,785) | (21,534,575) | (68,844,360) | |
Distribution and accretion on Series A preferred units | (7,956,092) | (3,293,877) | (11,249,969) | |
Distribution on Class B units | (76,780) | (76,780) | ||
Net loss | 30,647,893 | 11,789,981 | 42,437,874 | |
Unitholders' capital, ending balance at Dec. 31, 2021 | $ 328,717,841 | $ 880,579 | $ 19,251,361 | $ 348,849,781 |
Unitholders' capital, ending balance (in units) at Dec. 31, 2021 | 47,162,773 | 17,611,579 | 47,162,773 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income (loss) | $ 42,437,874 | $ (256,090,770) | $ (158,207,945) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation and depletion expense | 36,797,881 | 47,988,796 | 52,118,367 |
Impairment of oil and natural gas properties | 0 | 251,558,557 | 169,150,255 |
Amortization of right-of-use assets | 298,093 | 276,180 | 154,525 |
Amortization of loan origination costs | 1,556,769 | 1,108,685 | 1,050,278 |
Loss on extinguishment of debt | 476,350 | ||
Equity income in affiliate | (1,119,819) | (763,988) | (80,481) |
Cash distribution from affiliate | 1,015,559 | 812,810 | |
Forfeiture of restricted units | (127,934) | ||
Unit-based compensation | 10,632,725 | 9,261,756 | 7,502,678 |
Loss on derivative instruments, net of settlements | 20,343,783 | 7,085,364 | 3,423,445 |
Changes in operating assets and liabilities: | |||
Oil, natural gas and NGL receivables | (17,594,389) | 1,618,006 | 4,410,140 |
Accounts receivable and other current assets | (2,077,637) | (897,088) | (26,317) |
Accounts payable | (77,716) | (319,001) | (125,387) |
Other current liabilities | (463,828) | 533,582 | 1,762,633 |
Operating lease liabilities | (306,814) | (275,964) | (429,743) |
Net cash provided by operating activities | 91,442,481 | 62,245,341 | 80,702,448 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Purchases of property and equipment | (772,688) | (996,102) | (1,032,105) |
Purchase of oil and natural gas properties | (55,300,252) | (87,600,123) | (11,686,570) |
Investment in affiliate | (2,231,509) | (2,965,933) | |
Cash distribution from affiliate | 500,389 | 94,150 | |
Net cash used in investing activities | (55,572,551) | (90,827,734) | (15,590,458) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from equity offering | 57,522,440 | 73,601,668 | |
Contributions from Class B unitholders | 470,000 | ||
Redemption of Class B contributions on converted units | (158,410) | (363,748) | (273,250) |
Issuance costs paid on Series A preferred units | (717,612) | ||
Redemption on Series A preferred units | (67,081,680) | (61,089,600) | |
Distributions to common unitholders | (47,309,785) | (29,513,612) | (35,384,665) |
Distribution to OpCo unitholders | (21,534,575) | (20,507,481) | (35,672,648) |
Distribution and accretion on Series A preferred units | (2,800,012) | (4,812,509) | (7,700,000) |
Distribution on Class B units | (76,780) | (91,869) | (94,429) |
Borrowings on long-term debt | 136,565,769 | 162,614,665 | 12,825,933 |
Repayments on long-term debt | (91,000,000) | (91,200,000) | |
Payment of loan origination costs | (684,767) | (4,454,394) | (88,777) |
Restricted units repurchased for tax withholding | (2,064,693) | (46,279) | |
Net cash (used in) provided by financing activities | (38,622,493) | 24,183,120 | (66,681,727) |
NET DECREASE IN CASH AND CASH EQUIVALENTS | (2,752,563) | (4,399,273) | (1,569,737) |
CASH AND CASH EQUIVALENTS, beginning of period | 9,804,977 | 14,204,250 | 15,773,987 |
CASH AND CASH EQUIVALENTS, end of period | 7,052,414 | 9,804,977 | 14,204,250 |
Supplemental cash flow information: | |||
Cash paid for interest | 7,538,814 | 5,346,892 | 5,181,650 |
Cash paid for taxes | 801,669 | ||
Non-cash investing and financing activities: | |||
Units issued in exchange for oil and natural gas properties | 28,140,092 | 207,843,194 | |
Oil and natural gas property acquisition costs in accounts payable | 2,042 | ||
Non-cash effect of Series A preferred unit redemption | 14,983,784 | 25,847,891 | |
Non-cash deemed distribution to Series A preferred units | 9,431,794 | $ 2,998,079 | 6,178,336 |
Distribution to Series A preferred unitholders in accounts payable | 981,837 | ||
Right-of-use assets obtained in exchange for operating lease liabilities | 19,636 | $ 3,554,159 | |
Recognition of tenant improvement asset | $ 447,917 |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2021 | |
ORGANIZATION AND BASIS OF PRESENTATION | |
ORGANIZATION AND BASIS OF PRESENTATION | Unless the context otherwise requi res, references to “Kimbell Royalty Partners, LP,” “the Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner. References to “the Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership. NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION Organization Kimbell Royalty Partners, LP is a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest. Basis of Presentation The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows. Segment Reporting The Partnership operates in a single reportable COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas The global spread of coronavirus (“COVID-19”) created significant volatility, uncertainty, and economic disruption during year ended 2020. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic reached more than 200 countries and resulted in widespread adverse impacts on the global economy, the Partnership’s oil, natural gas, and NGL operators and other parties with whom the Partnership has business relations, including a significant reduction in the global demand for oil and natural gas during the year ended 2020. The significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance led to a significantly weaker outlook for oil and gas producers in 2020. The Partnership modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention (the “CDC”), the WHO and other governmental and regulatory authorities. In mid-March 2020, the Partnership restricted access to its offices to only essential employees and directed the remainder of its employees to work from home to the extent possible. Beginning in mid-May 2020, the Partnership opened its offices to employees on a voluntary basis, with employees having the option to work from the office or from home. The Partnership will continue to give employees the option to work from the office or from home until the CDC recommends businesses and employers resume to pre-pandemic operations. These restrictions have had minimal impact on the Partnership’s operations to date and have allowed the Partnership to maintain the engagement and connectivity of its personnel, as well as minimize the number of employees in the office. The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations remain dependent on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2021 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Management Estimates The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, recoverability of costs of unevaluated properties, valuation of commodity and interest rate derivative financial instruments and the fair value of equity-based compensation. The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion. Cash and Cash Equivalents The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents. At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits. Oil, Natural Gas and Receivables Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2021 and 2020, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs. Derivative Financial Instruments Commodity Derivatives The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within gain (loss) on commodity derivative instruments. Interest Rate Swaps The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps are recognized as gains or losses in the current period and are presented on a net basis within other income in the consolidated statements of operations. Property and Equipment Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three Oil and Natural Gas Properties The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made. While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties. The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2021, 2020 or 2019. The Partnership assesses all unevaluated properties on periodic 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: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test. Due to the nature of the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2021, 2020 or 2019. Other Current Liabilities Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short-term operating lease liabilities. Earnings Per Unit Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes, which became effective on September 24, 2018. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized. Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2021, 2020 and 2019. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2021, 2020 and 2019, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions. Concentration of Credit Risk The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations. During the years ended December 31, 2021, 2020 and 2019, the Partnership’s top Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. See Note 4 Non-controlling Interest Revenue from Contracts with Customers The Partnership has the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a mineral or royalty interest. Revenue 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. The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a mineral or royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL 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 NGL. 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 revenue does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s revenue contracts. Contract balances Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP 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 NGL sales may not be received for one four months Fair Value Measurements The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements. Recently Adopted Pronouncements In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The Partnership adopted this update on January 1, 2021 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2021. |
ACQUISITIONS, JOINT VENTURES AN
ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY | 12 Months Ended |
Dec. 31, 2021 | |
ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY | |
ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY | NOTE 3—ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY Acquisitions 2021 Activity On March 10, 2021, the Partnership completed the acquisition of certain mineral and royalty assets held by Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP for a total purchase price of $0.5 million. The assets acquired were managed by Nail Bay Royalties and Duncan Management, LLC (“Duncan Management”). See Note 14—Related Party Transactions, for further discussion of the Partnership’s relation to each entity. On December 7, 2021, certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”) 2020 Activity On April 17, 2020, the Partnership completed the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”). The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units representing limited partner interests in the Partnership (“common units”) and (iii) the issuance of 2,497,134 newly issued common units of the Operating Company (“OpCo common units”) and an equal number of newly issued Class B common units representing limited partner interests of the Partnership (“Class B units”). At the time of the Springbok Acquisition, the acreage acquired had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins. 2019 Activity On March 25, 2019, the Partnership acquired all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC that own oil and natural gas mineral and royalty interests (the “Phillips Acquisition”). The aggregate consideration for the Phillips Acquisition consisted of 9,400,000 OpCo common units and an equal number of Class B units On November 6, 2019, the Partnership acquired various mineral and royalty interests in Oklahoma for an aggregate purchase price of approximately $9.9 million. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired consist of approximately 279,680 gross acres and 186 net royalty acres. On December 12, 2019 consisted of 2,169,348 OpCo common units and an equal number of Class B units. The assets acquired in the Buckhorn Acquisition consisted of approximately 86,005 gross acres and 405 net royalty acres. Joint Ventures On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed its current investment of $5.1 million, as noted below. The Joint Venture is managed by Springbok Operating Company, LLC. While certain members of Springbok Operating Company, LLC are affiliated with the entities acquired as part of the Springbok Acquisition, none of the assets held by the Joint Venture were included in the Springbok Acquisition. The purpose of the Joint Venture is to make direct or indirect investments in royalty, mineral and overriding royalty interests and similar non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. The Partnership currently utilizes the equity method of accounting for its investment in the Joint Venture. As of December 31, 2021, the Partnership has invested approximately $5.1 million under its capital commitment. Special Purpose Acquisition Company On July 29, 2021, TGR, our newly formed special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the United States Securities and Exchange Commission (“SEC”). TGR’s initial public offering was completed on February 8, 2022, with 23,000,000 units offered, including 3,000,000 units upon the underwriter’s exercise of its over-allotment option in full, at a price of $10.00 per unit. Each unit consists of one share of Class A common stock and one-half of one redeemable warrant. Each whole warrant may be exercised for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors are members of the sponsor of TGR. In connection with the closing of TGR’s initial public offering on February 8, 2022, the Partnership funded $14.1 million to TGR in exchange for 14,100,000 redeemable warrants. Each such warrant entitles the holder to purchase for $11.50, one share of TGR’s class A common stock, subject to adjustment. As of December 31, 2021, we incurred $0.9 million in deferred offering costs related to the proposed offering, which is included in other current assets in our consolidated balance sheets. |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2021 | |
DERIVATIVES | |
DERIVATIVES | NOTE 4—DERIVATIVES Commodity Derivatives The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. At December 31, 2021, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The Partnership hedges its daily production based on the amount of debt and/or preferred equity as a percent of its enterprise value. As of December 31, 2021, these economic hedges constituted approximately 32% of daily oil and natural gas production. The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying consolidated statements of operations. Interest Rate Swaps On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”) The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in the fair value consisted of the following: Year Ended December 31, 2021 2020 2019 Beginning fair value of derivative instruments $ (6,280,863) $ 804,501 $ 4,227,946 Loss on derivative instruments (41,240,942) (2,450,541) (1,732,321) Net cash paid (received) on settlements of derivative instruments 20,897,159 (4,634,823) (1,691,124) Ending fair value of derivative instruments $ (26,624,646) $ (6,280,863) $ 804,501 The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated: December 31, December 31, Classification Balance Sheet Location 2021 2020 Assets: Current assets Derivative assets 166,307 — Long-term assets Derivative assets $ 1,590,501 $ — Liabilities: Current liabilities Derivative liabilities (24,190,678) (3,113,178) Long-term liabilities Derivative liabilities (4,190,776) (3,167,685) $ (26,624,646) $ (6,280,863) At December 31, 2021, the Partnership’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional Weighted Average Range (per Bbl) Volumes (Bbl) Fixed Price (per Bbl) Low High January 2022 - December 2022 500,552 $ 41.86 $ 35.65 $ 46.00 January 2023 - December 2023 303,411 $ 59.35 $ 53.38 $ 63.00 Natural Gas Price Swaps Notional Weighted Average Range (per MMBtu) Volumes (MMBtu) Fixed Price (per MMBtu) Low High January 2022 - December 2022 6,357,449 $ 2.46 $ 2.23 $ 2.70 January 2023 - December 2023 4,245,899 $ 2.90 $ 2.52 $ 3.28 |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2021 | |
FAIR VALUE MEASUREMENTS | |
FAIR VALUE MEASUREMENTS | NOTE 5—FAIR VALUE MEASUREMENTS The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the consolidated balance sheets approximated fair value at December 31, 2021 and 2020 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below. ● Level 1—Unadjusted quoted market prices for identical assets or liabilities in active markets. ● Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the asset or liability. ● Level 3— Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value). Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the years ended December 31, 2021 and 2020. Both the Partnership’s commodity derivative instruments and interest rate swap are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy: Fair Value Measurements Using Level 1 Level 2 Level 3 Effect of Counterparty Netting Total December 31, 2021 Assets Interest rate swap contracts $ — $ 1,756,808 $ — $ — $ 1,756,808 Liabilities Commodity derivative contracts $ — $ (28,381,454) $ — $ — $ (28,381,454) December 31, 2020 Liabilities Commodity derivative contracts $ — $ (6,280,863) $ — $ — $ (6,280,863) |
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES | 12 Months Ended |
Dec. 31, 2021 | |
OIL AND NATURAL GAS PROPERTIES | |
OIL AND NATURAL GAS PROPERTIES | NOTE 6 — OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties consist of the following: December 31, December 31, 2021 2020 Oil and natural gas properties Proved properties $ 1,051,111,311 $ 923,413,606 Unevaluated properties 153,284,173 225,681,626 Less: accumulated depreciation, depletion and impairment (663,603,142) (628,102,279) Total oil and natural gas properties $ 540,792,342 $ 520,992,953 After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined in 2020 that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties in the first quarter of 2020. The Partnership did not book PUD reserves in its total estimated proved reserves as of December 31, 2021 or 2020 and it does not intend to book PUD reserves going forward. The Partnership did not record an impairment on its oil and natural gas properties for the year ended December 31, 2021 due to the increase in the twelve-month average oil and gas index prices, calculated as the unweighted average for first-day-of-the-month price for each month. As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $251.6 million during the year ended December 31, 2020, including the $48.6 million in unevaluated properties transferred to the full cost pool. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas during the year ended December 31, 2020. The Partnership recorded an impairment on its oil and natural gas properties of $169.2 million during the year ended December 31, 2019, as a result of its quarterly full cost ceiling analysis and a decline in the 12-month average price of oil and natural gas. |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2021 | |
LEASES | |
LEASES | NOTE 7—LEASES Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying consolidated balance sheets. Short-term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2021 is 7.35 years. Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the year ended December 31, 2021. Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019. The total operating lease expense recorded for the years ended December 31, 2021, 2020 and 2019 was $0.4 million, $0.5 million and $0.3 million, respectively. Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations. In July 2019, the Partnership became the lessee in several other related lease agreements for additional office space. In addition, the Partnership was involved in the construction and design of the underlying assets. Future minimum lease commitments as of December 31, 2021 were as follows: Total 2022 2023 2024 2025 2026 Thereafter Operating leases $ 3,686,505 $ 486,045 $ 487,787 $ 488,725 $ 497,033 $ 507,648 $ 1,219,267 Less: Imputed Interest (823,006) Total $ 2,863,499 |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2021 | |
LONG-TERM DEBT. | |
LONG-TERM DEBT | NOTE 8—LONG-TERM DEBT On January 11, 2017, the Partnership entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, the Partnership entered into an amendment (the “First Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”). On December 8, 2020, the Partnership entered into Amendment No. 2 (the “Second Credit Agreement Amendment”) to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”). The Second Credit Agreement Amendment amends the 2018 Amended Credit Agreement to, among other things, (i) increase commitments under the Amended Credit Agreement’s senior secured revolving credit facility from $225.0 million to $265.0 million, the availability of which will equal the lesser of the aggregate maximum elected commitments of the lenders up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing base, (ii) extend the maturity date under the 2018 Amended Credit Agreement from February 8, 2022 to June 7, 2024, (iii) reflect the change in administrative agent from Frost to Citibank under the Amended Credit Agreement, (iv) increase the applicable margin under the 2018 Amended Credit Agreement, which varies based upon the level of borrowing base usage, by 1.00% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 2.00% to 3.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 3.00% to 4.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement), (v) a LIBOR (as defined in the Amended Credit Agreement) floor of 0.25% , (vi) modify the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) financial covenant to permit the numerator of the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) to be calculated as Total Debt (as defined in the Amended Credit Agreement) minus up to $25 million in unrestricted cash held by the Partnership and its restricted subsidiaries and to decreases the maximum permitted Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) from 4.0 to 1.0 to 3.5 to 1.0, and (vii) modify the conditions permitting restricted distributions to holders of Kimbell Common Units (as defined in the Amended Credit Agreement) including, among other things, a limitation on such distributions to not be in excess of the Partnership’s Projected Cash Available For Distribution (as defined in the Amended Credit Agreement). We are obligated to pay a quarterly commitment fee of 0.50% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing based. In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year, beginning May 1, 2021, based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the Partnership’s wholly owned subsidiaries. In connection with the November 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was increased to $275.0 million. The Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units and OpCo common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The Amended Credit Agreement also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement 3.5 1.0 The Amended Credit Agreement also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change of control. In connection with the Second Credit Agreement Amendment, the Partnership recorded a loss on extinguishment of debt of $0.5 million for the year ended December 31, 2020, as a result of writing off all unamortized loan origination costs associated with the lenders to the 2017 Credit Agreement and the 2018 Amended Credit Agreement that did not participate in the Second Credit Agreement Amendment. During the year ended December 31, 2021, the Partnership borrowed an additional $136.6 million under the secured revolving credit facility and repaid approximately $91.0 million of the outstanding borrowings. As of December 31, 2021, the Partnership’s outstanding balance was $217.1 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2021. As of December 31, 2021, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 3.75% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.75%. For the year ended December 31, 2021, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.86%. |
PREFERRED UNITS
PREFERRED UNITS | 12 Months Ended |
Dec. 31, 2021 | |
PREFERRED UNITS | |
PREFERRED UNITS | NOTE 9—PREFERRED UNITS In July 2018, the Partnership completed the private placement of 110,000 newly issued Series A Cumulative Convertible Preferred Units (“Series A preferred units”) to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million. Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units. In May 2021, the Series A Purchasers and the Partnership agreed to waive the board observer rights, that were set to begin in July 2021, until January 2022. The Series A preferred units are convertible by the Series A Purchasers after two years at a 30% discount to the issue price, subject to certain conditions. The Partnership may redeem the Series A preferred units at any time. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of July 12, 2018 (the “Series A Issuance Date”), a 13.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary of the Series A Issuance Date, a 14.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the Series A Issuance Date, a 15.0% internal rate of return with respect to the Series A preferred units. On February 12, 2020, the Partnership completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $5.7 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2020. On July 7, 2021, the Partnership completed the redemption of 30,000 Series A preferred units, representing 55% of the then-outstanding Series A preferred units, with 25,000 Series A preferred units still outstanding. The Series A preferred units were redeemed at a price of $1,202.51 per Series A preferred unit for an aggregate redemption price of $36.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date and the redeemed portion of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $3.8 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2021. On December 7, 2021, the Partnership completed the redemption of the remaining 25,000 Series A preferred units. The Series A preferred units were redeemed at a price of $1,240.25 per Series A preferred unit for an aggregate redemption price of $31.0 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date and the remaining intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $3.6 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2021. The following table summarizes the changes in the number of the Series A preferred units: Series A Preferred Units Balance at December 31, 2020 55,000 Redemption of Series A preferred units (55,000) Balance at December 31, 2021 - |
UNITHOLDERS' EQUITY AND PARTNER
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS | 12 Months Ended |
Dec. 31, 2021 | |
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS | |
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS | NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS The Partnership has issued units representing limited partner interests. At December 31, 2021, the Partnership had a total of 47,162,773 common units issued and outstanding In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). The Partnership used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units pursuant to the exercise of the underwriters’ option to purchase additional common units. The Partnership did not receive any proceeds from the sale of the common units by the selling unitholders. In November 2021, the Partnership completed an underwritten public offering of 4,312,500 common units for net proceeds of approximately $57.7 million (the “2021 Equity Offering”). The Partnership used the net proceeds from the 2021 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $56.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. The following table summarizes the changes in the number of the Partnership’s common units: Common Units Balance at December 31, 2020 38,918,689 Common units issued for equity offering 4,312,500 Conversion of Class B units 3,168,202 Common units issued under the LTIP (1) 936,567 Restricted units repurchased for tax withholding (173,185) Balance at December 31, 2021 47,162,773 (1) Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 25, 2021. The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented: Amount per Date Unitholder Payment Common Unit Declared Record Date Date Q1 2021 $ 0.27 April 23, 2021 May 3, 2021 May 10, 2021 Q2 2021 $ 0.31 July 23, 2021 August 2, 2021 August 9, 2021 Q3 2021 $ 0.37 October 22, 2021 November 1, 2021 November 8, 2021 Q4 2021 $ 0.37 January 21, 2022 January 31, 2022 February 7, 2022 Q1 2020 $ 0.17 April 24, 2020 May 4, 2020 May 11, 2020 Q2 2020 $ 0.13 July 24, 2020 August 3, 2020 August 10, 2020 Q3 2020 $ 0.19 October 23, 2020 November 2, 2020 November 9, 2020 Q4 2020 $ 0.19 January 22, 2021 February 1, 2021 February 8, 2021 Q1 2019 $ 0.37 April 26, 2019 May 6, 2019 May 13, 2019 Q2 2019 $ 0.39 July 26, 2019 August 5, 2019 August 12, 2019 Q3 2019 $ 0.42 October 25, 2019 November 4, 2019 November 11, 2019 Q4 2019 $ 0.38 January 24, 2020 February 3, 2020 February 10, 2020 The following table summarizes the changes in the number of the Partnership’s Class B units: Class B Units Balance at December 31, 2020 20,779,781 Conversion of Class B units (3,168,202) Balance at December 31, 2021 17,611,579 For each Class B unit issued, five cents has been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units and OpCo common units. Holders of the Class B units are entitled to one vote per share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP. The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership. |
EARNINGS (LOSS) PER COMMON UNIT
EARNINGS (LOSS) PER COMMON UNIT | 12 Months Ended |
Dec. 31, 2021 | |
EARNINGS (LOSS) PER COMMON UNIT | |
EARNINGS (LOSS) PER COMMON UNIT | NOTE 11—EARNINGS (LOSS) PER COMMON UNIT Basic earnings (loss) per common unit is calculated by dividing net income (loss) attributable to common units 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 restricted units granted under the Partnership’s LTIP for its employees, directors and consultants and potential conversion of Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the Partnership’s LTIP. The Partnership does not use the two-class method because the Class B units and the unvested restricted units granted under the Partnership’s LTIP are nonparticipating securities. The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings (loss) per common unit: Year Ended December 31, 2021 2020 2019 Net income (loss) attributable to common units $ 22,615,021 $ (167,350,893) $ (83,032,282) Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interests 8,496,104 — — Diluted net income (loss) attributable to common units 31,111,125 (167,350,893) (83,032,282) Weighted average number of common units outstanding: Basic 40,400,907 34,530,398 21,192,714 Effect of dilutive securities: Series A preferred units — — — Class B units 18,839,607 — — Restricted units 1,717,310 — — Diluted 60,957,824 34,530,398 21,192,714 Net income (loss) attributable to common units Basic $ 0.56 $ (4.85) $ (3.92) Diluted $ 0.51 $ (4.85) $ (3.92) The calculation of diluted net income per share for the year ended December 31, 2021 includes the conversion of all Class B units to common units calculated using the “if-converted” method and 1,717,310 units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net loss per share for the years ended December 31, 2020 and 2019 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,276,546 and 739,479 units of unvested restricted units, respectively, because their inclusion in the calculation would be anti-dilutive. |
UNIT-BASED COMPENSATION
UNIT-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2021 | |
UNIT-BASED COMPENSATION | |
UNIT-BASED COMPENSATION | NOTE 12—UNIT-BASED COMPENSATION The Partnership’s LTIP authorizes grants of up to 4,541,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued one three Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued Weighted Weighted Average Average Grant-Date Remaining Fair Value Contractual Units per Unit Term Unvested at December 31, 2020 1,276,546 $ 13.604 1.788 years Awarded 936,567 10.350 — Vested (652,214) 14.905 — Unvested at December 31, 2021 1,560,899 $ 11.108 1.775 years |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2021 | |
INCOME TAXES | |
INCOME TAXES | NOTE 13—INCOME TAXES As discussed further in Note 1, on May 28, 2018, the Board of Directors unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership incurred de minimis amounts of income taxes during the years ended December 31, 2021, 2020 and 2019. The Partnership has filed all tax returns to date that are currently due. On March 27, 2020, the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act “) was enacted. The CARES Act is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing COVID-19 pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses that under previous law were only available to be carried forward. The Partnership’s effective income tax rate was 0.17% for the year ended December 31, 2021. The Partnership earned book income for the current year and is recording a current income tax expense of $0.1 million primarily related to unsheltered taxable income. Year Ended December 31, 2021 2020 2019 Current Federal $ 69,067 $ (812,913) $ 812,913 State 5,033 (72,280) 86,512 Total Current 74,100 (885,193) 899,425 Deferred Federal — — — State — — — Total Deferred — — — Provision for (benefit from) income taxes $ 74,100 $ (885,193) $ 899,425 The Partnership’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items: Year Ended December 31, 2021 2020 2019 Net income (loss) before taxes $ 42,511,974 $ (256,975,963) $ (157,308,520) Statutory rate 21 % 21 % 21 % Income tax provision (benefit) computed at statutory rate 8,927,515 (53,964,952) (33,034,789) Reconciling items: State income taxes 5,033 (72,280) 72,280 Non-controlling interest (1,788,347) 20,294,890 18,721,170 (Income) loss at OpCo (7,139,168) 33,670,062 15,130,685 Change in valuation allowance - federal (363,132) (749,866) 80,520 Change in valuation allowance - state (40,626) 168,393 (70,441) Other, net 472,825 (231,440) — Provision for (benefit from) income taxes $ 74,100 $ (885,193) $ 899,425 Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Partnership’s deferred taxes are detailed in the table below. Year Ended December 31, 2021 2020 2019 Deferred tax asset Outside basis in OpCo $ 6,641,452 $ 17,624,909 $ 20,050,732 Federal tax loss carryforwards 12,296,282 1,675,957 — State tax loss carryforwards 1,789,961 238,559 — Deferred tax asset 20,727,695 19,539,425 20,050,732 Valuation allowance (20,727,695) (19,539,425) (20,050,732) Net deferred tax asset $ — $ — $ — Deferred tax liability Derivative instruments and other — — — Net deferred tax liability $ — $ — $ — Reflected in the accompanying balance sheets as: Net deferred tax asset $ — $ — $ — Net deferred tax liability $ — $ — $ — The tax years ended December 31, 2018 through 2021 remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Partnership and its subsidiaries file income tax returns. In some instances, state statutes of limitations are longer than those under United States federal tax law. The Partnership believes that it is more likely than not that the benefit from the outside basis differences in the Partnership’s investment in the Operating Company and its federal and state loss carryforward will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $20.7 million on the deferred tax assets. As of December 31, 2021, the Partnership has not |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2021 | |
RELATED PARTY TRANSACTIONS | |
RELATED PARTY TRANSACTIONS | NOTE 14—RELATED PARTY TRANSACTIONS The Partnership has entered into a management services agreement with Kimbell Operating, which has entered into separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”), pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution on common units to the Partnership’s unitholders. During the year ended December 31, 2021, no monthly services fee was paid to BJF Royalties. During the year ended December 31, 2021, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $120,000, $301,314 and $548,480, respectively. Certain consultants who provide services under the management services agreements are also granted restricted units under the Partnership’s LTIP. During the year ended December 31, 2021, the Partnership acquired certain assets managed by Nail Bay Royalties and Duncan Management. See Note 3 John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of approximately $22,160, $20,160 and $18,900 for the years ended December 31, 2021, 2020 and 2019, respectively, for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $555,640, $440,160 and $350,000 for the years ended December 31, 2021, 2020 and 2019, respectively. Special Purpose Acquisition Company On February 8, 2022, TGR’s initial public offering was completed with 23,000,000 units offered, including 3,000,000 units upon the underwriter’s exercise of its over-allotment option in full, at a price of $10.00 per unit. During the year ended December 31, 2021, the Partnership paid $930,824 in formation and offering costs on behalf of TGR. This amount is included in other current assets on the consolidated balance sheets as of December 31, 2021. See Note 3—Acquisitions, Joint Ventures and Special Purpose Acquisition Company for further discussion. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2021 | |
COMMITMENTS AND CONTINGENCIES. | |
COMMITMENTS AND CONTINGENCIES | NOTE 15—COMMITMENTS AND CONTINGENCIES Leases The Partnership leases certain office space under non-cancelable operating leases with fixed payment terms and will terminate in June 2029. The Partnership recognizes operating lease expense over the lease term and is included in general and administrative expense in the accompanying consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019. The total operating lease expense recorded for the years ended December 31, 2021, 2020 and 2019 was approximately $0.4 million, $0.5 million and $0.3 million, respectively. Operating lease liabilities, excluding the current portion, as of the year ended December 31, 2021 and 2020, respectively, was $2.6 million and $2.8 million. Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2021: Years Ending December 31, 2022 $ 486,045 2023 487,787 2024 488,725 2025 497,033 2026 507,648 Thereafter 1,219,267 Total $ 3,686,505 Litigation During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity as of December 31, 2021. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2021 | |
SUBSEQUENT EVENTS | |
SUBSEQUENT EVENTS | NOTE 16—SUBSEQUENT EVENTS The Partnership has evaluated events that occurred subsequent to December 31, 2021 in the preparation of its consolidated financial statements. Debt On January 14, 2022 and January 27, 2022, the Partnership drew down approximately $12.9 million and $1.2 million, respectively, on the senior secured revolving credit facility to fund the closing of TGR’s initial public offering on February 8, 2022. On January 28, 2022, the Partnership drew down $5.0 million on the senior secured revolving credit facility to fund certain operational expenses. Distributions On February 7, 2022, the Partnership paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of $17,610 for the quarter ended December 31, 2021. On January 21, 2022, the Board of Directors declared a quarterly cash distribution of $0.37 per common unit for the quarter ended December 31, 2021. The distribution was paid on February 7, 2022 to common unitholders and OpCo common unitholders of record as of the close of business on January 31, 2022. On February 24, 2022, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of $2.2 million and the issuance of 963,835 restricted units to its employees, directors and consultants. Special Purpose Acquisition Company On February 8, 2022, TGR’s initial public offering was completed with 23,000,000 units offered, including 3,000,000 units upon the underwriter’s exercise of its over-allotment option in full, at a price of $10.00 per unit. See Note 3—Acquisitions, Joint Ventures and Special Purpose Acquisition Company for further discussion. |
SUPPLEMENTAL OIL AND GAS RESERV
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | 12 Months Ended |
Dec. 31, 2021 | |
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | |
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | NOTE 17—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities. 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, December 31, 2021 2020 Oil, natural gas and NGL interests Proved properties $ 1,051,111,311 $ 923,413,606 Unevaluated properties 153,284,173 225,681,626 Total oil, natural gas and NGL interests 1,204,395,484 1,149,095,232 Accumulated depreciation, depletion, accretion and impairment (663,603,142) (628,102,279) Net oil, natural gas and NGL interests capitalized $ 540,792,342 $ 520,992,953 Costs incurred in oil and natural gas activities Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows: Year Ended December 31, 2021 2020 2019 Acquisition costs Proved properties $ 55,300,252 $ 41,476,733 $ 104,199,579 Unevaluated properties — 74,263,481 110,050,000 Total 55,300,252 115,740,214 214,249,579 Development costs Proved properties — — — Total — — — Total costs incurred on oil, natural gas and NGL activities $ 55,300,252 $ 115,740,214 $ 214,249,579 Results of Operations from Oil, Natural Gas and NGL Producing Activities The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and NGL operations. Year Ended December 31, 2021 2020 2019 Oil, natural gas and NGL revenues $ 175,088,021 $ 92,586,685 $ 107,480,446 Lease bonus and other income 3,319,104 345,771 2,477,145 Production and ad valorem taxes (10,480,481) (6,389,231) (7,719,949) Depreciation and depletion expense (36,797,881) (47,988,796) (52,118,367) Impairment of oil and natural gas properties — (251,558,557) (169,150,255) Marketing and other deductions (12,048,643) (9,376,375) (8,145,397) Results of operations from oil, natural gas and NGLs $ 119,080,120 $ (222,380,503) $ (127,176,377) The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves, and the estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2021, 2020 and 2019. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC. Proved Oil, Natural Gas and NGL Reserve Quantities Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. PUD reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a price equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below: Crude Oil and Natural Gas Condensate Natural Gas Liquids Total (MBbls) (MMcf) (MBbls) (MBOE) Net proved reserves at January 1, 2019 10,795 127,261 5,646 37,651 Revisions of previous estimates (1) 849 25,398 684 5,766 Purchase of minerals in place (2) 1,787 13,129 686 4,661 Production (1,113) (17,046) (561) (4,515) Net proved reserves at December 31, 2019 12,318 148,742 6,455 43,563 Revisions of previous estimates (1) 18 (2,256) (2) (359) Purchase of minerals in place (3) 1,367 15,637 313 4,286 Production (1,409) (17,890) (681) (5,072) Net proved reserves at December 31, 2020 12,294 144,233 6,085 42,418 Revisions of previous estimates (1) 251 24,079 780 5,044 Purchase of minerals in place (4) 1,310 8,537 519 3,252 Production (1,344) (19,085) (715) (5,240) Net proved reserves at December 31, 2021 12,511 157,764 6,669 45,474 Net proved developed reserves December 31, 2019 11,303 141,181 6,079 40,912 December 31, 2020 12,294 144,233 6,085 42,418 December 31, 2021 12,511 157,764 6,669 45,474 Net proved undeveloped reserves December 31, 2019 1,015 7,561 376 2,651 December 31, 2020 — — — — December 31, 2021 — — — — (1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. (2) Includes the acquisition of three packages of mineral and royalty interests for a total of $103.8 million. The first acquisition totaling $58.4 million consists of mineral and royalty interests primarily in the Eagle Ford Shale, Permian Basin, East Texas Region and Appalachia Region. The second acquisition totaling $9.4 million consists of mineral and royalty interests in the Mid-Continent Region. The third acquisition totaling $36.0 million consists of mineral and royalty interests in the Eagle Ford Shale. (3) Includes the acquisition of mineral and royalty interests for a total of $41.5 million. The acquisition consists of mineral and royalty interests primarily in the Delaware Basin, DJ Basin, Haynesville, STACK and Eagle Ford. (4) Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in the Permian Basin, Mid-Continent, Haynesville and other leading U.S. basins. 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. Standardized Measure The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands): Year Ended December 31, 2021 2020 2019 Future cash inflows $ 1,335,917 $ 705,356 $ 1,025,430 Future production costs (100,947) (55,897) (78,061) Future state margin taxes (42,965) (22,688) (32,377) Future income tax expense — — (33,235) Future net cash flows 1,192,005 626,771 881,757 Less 10% annual discount to reflect timing of cash flows (665,390) (341,775) (481,786) Standard measure of discounted future net cash flows $ 526,615 $ 284,996 $ 399,971 Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2021, 2020 and 2019 were $66.56, $39.57 and $55.69 per barrel for crude oil and $3.60, $1.99 and $2.58 per Mcf for natural gas, respectively. Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates. Changes in Standardized Measure Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Standardized measure - beginning of year $ 284,996 $ 399,971 $ 398,367 Sales, net of production costs (152,751) (76,821) (93,942) Net changes of prices and production costs related to future production 225,868 (127,838) (72,875) Revisions of previous quantity estimates, net of related costs 60,517 (2,501) 56,666 Net changes in state margin taxes (8,665) 4,314 191 Net changes in income taxes — 13,480 3,752 Accretion of discount 25,743 38,927 42,808 Purchases of reserves in place 40,545 46,007 59,953 Timing differences and other 50,362 (10,543) 5,051 Standardized measure - end of year $ 526,615 $ 284,996 $ 399,971 |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
Basis of Presentation | Basis of Presentation The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows. |
Segment Reporting | Segment Reporting The Partnership operates in a single reportable |
Management Estimates | Management Estimates The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, recoverability of costs of unevaluated properties, valuation of commodity and interest rate derivative financial instruments and the fair value of equity-based compensation. The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents. At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits. |
Oil, Natural Gas and Receivables | Oil, Natural Gas and Receivables Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2021 and 2020, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs. |
Derivative Financial Instruments | Derivative Financial Instruments Commodity Derivatives The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within gain (loss) on commodity derivative instruments. Interest Rate Swaps The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps are recognized as gains or losses in the current period and are presented on a net basis within other income in the consolidated statements of operations. |
Property and Equipment | Property and Equipment Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made. While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties. The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2021, 2020 or 2019. The Partnership assesses all unevaluated properties on periodic 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: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test. Due to the nature of the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2021, 2020 or 2019. |
Other Current Liabilities | Other Current Liabilities Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short-term operating lease liabilities. |
Earnings Per Unit | Earnings Per Unit |
Income Taxes | Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes, which became effective on September 24, 2018. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized. Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2021, 2020 and 2019. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2021, 2020 and 2019, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions. |
Concentration of Credit Risk | Concentration of Credit Risk The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations. During the years ended December 31, 2021, 2020 and 2019, the Partnership’s top Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. See Note 4 |
Non-controlling Interest | Non-controlling Interest |
Revenue from Contracts with Customers | Revenue from Contracts with Customers The Partnership has the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a mineral or royalty interest. Revenue 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. The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a mineral or royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL 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 NGL. 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 revenue does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s revenue contracts. Contract balances Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP 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 NGL sales may not be received for one four months |
Fair Value Measurements | Fair Value Measurements The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements. |
Recently Adopted Pronouncements | Recently Adopted Pronouncements In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The Partnership adopted this update on January 1, 2021 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2021. |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
DERIVATIVES | |
Schedule of changes in fair value of derivative instruments | Year Ended December 31, 2021 2020 2019 Beginning fair value of derivative instruments $ (6,280,863) $ 804,501 $ 4,227,946 Loss on derivative instruments (41,240,942) (2,450,541) (1,732,321) Net cash paid (received) on settlements of derivative instruments 20,897,159 (4,634,823) (1,691,124) Ending fair value of derivative instruments $ (26,624,646) $ (6,280,863) $ 804,501 |
Schedule of derivative contracts | December 31, December 31, Classification Balance Sheet Location 2021 2020 Assets: Current assets Derivative assets 166,307 — Long-term assets Derivative assets $ 1,590,501 $ — Liabilities: Current liabilities Derivative liabilities (24,190,678) (3,113,178) Long-term liabilities Derivative liabilities (4,190,776) (3,167,685) $ (26,624,646) $ (6,280,863) |
Schedule of commodity derivative contracts | Oil Price Swaps Notional Weighted Average Range (per Bbl) Volumes (Bbl) Fixed Price (per Bbl) Low High January 2022 - December 2022 500,552 $ 41.86 $ 35.65 $ 46.00 January 2023 - December 2023 303,411 $ 59.35 $ 53.38 $ 63.00 Natural Gas Price Swaps Notional Weighted Average Range (per MMBtu) Volumes (MMBtu) Fixed Price (per MMBtu) Low High January 2022 - December 2022 6,357,449 $ 2.46 $ 2.23 $ 2.70 January 2023 - December 2023 4,245,899 $ 2.90 $ 2.52 $ 3.28 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
FAIR VALUE MEASUREMENTS | |
Schedule of assets and liabilities measured at fair value on a recurring basis | Fair Value Measurements Using Level 1 Level 2 Level 3 Effect of Counterparty Netting Total December 31, 2021 Assets Interest rate swap contracts $ — $ 1,756,808 $ — $ — $ 1,756,808 Liabilities Commodity derivative contracts $ — $ (28,381,454) $ — $ — $ (28,381,454) December 31, 2020 Liabilities Commodity derivative contracts $ — $ (6,280,863) $ — $ — $ (6,280,863) |
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
OIL AND NATURAL GAS PROPERTIES | |
Schedule of oil and natural gas properties | December 31, December 31, 2021 2020 Oil and natural gas properties Proved properties $ 1,051,111,311 $ 923,413,606 Unevaluated properties 153,284,173 225,681,626 Less: accumulated depreciation, depletion and impairment (663,603,142) (628,102,279) Total oil and natural gas properties $ 540,792,342 $ 520,992,953 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
LEASES | |
Schedule of future minimum lease commitments | Total 2022 2023 2024 2025 2026 Thereafter Operating leases $ 3,686,505 $ 486,045 $ 487,787 $ 488,725 $ 497,033 $ 507,648 $ 1,219,267 Less: Imputed Interest (823,006) Total $ 2,863,499 |
PREFERRED UNITS (Tables)
PREFERRED UNITS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Series A Preferred Units | |
Preferred units | |
Summary of the changes in the number of the Series A Preferred Units | Series A Preferred Units Balance at December 31, 2020 55,000 Redemption of Series A preferred units (55,000) Balance at December 31, 2021 - |
UNITHOLDERS' EQUITY AND PARTN_2
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Common units | |
Schedule of distributions approved by the Board of Directors | Amount per Date Unitholder Payment Common Unit Declared Record Date Date Q1 2021 $ 0.27 April 23, 2021 May 3, 2021 May 10, 2021 Q2 2021 $ 0.31 July 23, 2021 August 2, 2021 August 9, 2021 Q3 2021 $ 0.37 October 22, 2021 November 1, 2021 November 8, 2021 Q4 2021 $ 0.37 January 21, 2022 January 31, 2022 February 7, 2022 Q1 2020 $ 0.17 April 24, 2020 May 4, 2020 May 11, 2020 Q2 2020 $ 0.13 July 24, 2020 August 3, 2020 August 10, 2020 Q3 2020 $ 0.19 October 23, 2020 November 2, 2020 November 9, 2020 Q4 2020 $ 0.19 January 22, 2021 February 1, 2021 February 8, 2021 Q1 2019 $ 0.37 April 26, 2019 May 6, 2019 May 13, 2019 Q2 2019 $ 0.39 July 26, 2019 August 5, 2019 August 12, 2019 Q3 2019 $ 0.42 October 25, 2019 November 4, 2019 November 11, 2019 Q4 2019 $ 0.38 January 24, 2020 February 3, 2020 February 10, 2020 |
Common Units | |
Common units | |
Schedule of changes in Partnership's units | Common Units Balance at December 31, 2020 38,918,689 Common units issued for equity offering 4,312,500 Conversion of Class B units 3,168,202 Common units issued under the LTIP (1) 936,567 Restricted units repurchased for tax withholding (173,185) Balance at December 31, 2021 47,162,773 (1) Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 25, 2021. |
Class B | |
Common units | |
Schedule of changes in Partnership's units | Class B Units Balance at December 31, 2020 20,779,781 Conversion of Class B units (3,168,202) Balance at December 31, 2021 17,611,579 |
EARNINGS (LOSS) PER COMMON UN_2
EARNINGS (LOSS) PER COMMON UNIT (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
EARNINGS (LOSS) PER COMMON UNIT | |
Schedule of earnings (loss) per unit | Year Ended December 31, 2021 2020 2019 Net income (loss) attributable to common units $ 22,615,021 $ (167,350,893) $ (83,032,282) Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interests 8,496,104 — — Diluted net income (loss) attributable to common units 31,111,125 (167,350,893) (83,032,282) Weighted average number of common units outstanding: Basic 40,400,907 34,530,398 21,192,714 Effect of dilutive securities: Series A preferred units — — — Class B units 18,839,607 — — Restricted units 1,717,310 — — Diluted 60,957,824 34,530,398 21,192,714 Net income (loss) attributable to common units Basic $ 0.56 $ (4.85) $ (3.92) Diluted $ 0.51 $ (4.85) $ (3.92) |
UNIT-BASED COMPENSATION (Tables
UNIT-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
UNIT-BASED COMPENSATION | |
Schedule of unvested restricted stock activity | Weighted Weighted Average Average Grant-Date Remaining Fair Value Contractual Units per Unit Term Unvested at December 31, 2020 1,276,546 $ 13.604 1.788 years Awarded 936,567 10.350 — Vested (652,214) 14.905 — Unvested at December 31, 2021 1,560,899 $ 11.108 1.775 years |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
INCOME TAXES | |
Schedule of income tax expense | Year Ended December 31, 2021 2020 2019 Current Federal $ 69,067 $ (812,913) $ 812,913 State 5,033 (72,280) 86,512 Total Current 74,100 (885,193) 899,425 Deferred Federal — — — State — — — Total Deferred — — — Provision for (benefit from) income taxes $ 74,100 $ (885,193) $ 899,425 |
Schedule of effective income expense | Year Ended December 31, 2021 2020 2019 Net income (loss) before taxes $ 42,511,974 $ (256,975,963) $ (157,308,520) Statutory rate 21 % 21 % 21 % Income tax provision (benefit) computed at statutory rate 8,927,515 (53,964,952) (33,034,789) Reconciling items: State income taxes 5,033 (72,280) 72,280 Non-controlling interest (1,788,347) 20,294,890 18,721,170 (Income) loss at OpCo (7,139,168) 33,670,062 15,130,685 Change in valuation allowance - federal (363,132) (749,866) 80,520 Change in valuation allowance - state (40,626) 168,393 (70,441) Other, net 472,825 (231,440) — Provision for (benefit from) income taxes $ 74,100 $ (885,193) $ 899,425 |
Schedule of components of deferred tax assets and liabilities | Year Ended December 31, 2021 2020 2019 Deferred tax asset Outside basis in OpCo $ 6,641,452 $ 17,624,909 $ 20,050,732 Federal tax loss carryforwards 12,296,282 1,675,957 — State tax loss carryforwards 1,789,961 238,559 — Deferred tax asset 20,727,695 19,539,425 20,050,732 Valuation allowance (20,727,695) (19,539,425) (20,050,732) Net deferred tax asset $ — $ — $ — Deferred tax liability Derivative instruments and other — — — Net deferred tax liability $ — $ — $ — Reflected in the accompanying balance sheets as: Net deferred tax asset $ — $ — $ — Net deferred tax liability $ — $ — $ — |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
COMMITMENTS AND CONTINGENCIES. | |
Schedule of future minimum lease commitments | Years Ending December 31, 2022 $ 486,045 2023 487,787 2024 488,725 2025 497,033 2026 507,648 Thereafter 1,219,267 Total $ 3,686,505 |
SUPPLEMENTAL OIL AND GAS RESE_2
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | |
Schedule of oil and natural gas aggregate capitalized costs and applicable accumulated depreciation, depletion and amortization | December 31, December 31, 2021 2020 Oil, natural gas and NGL interests Proved properties $ 1,051,111,311 $ 923,413,606 Unevaluated properties 153,284,173 225,681,626 Total oil, natural gas and NGL interests 1,204,395,484 1,149,095,232 Accumulated depreciation, depletion, accretion and impairment (663,603,142) (628,102,279) Net oil, natural gas and NGL interests capitalized $ 540,792,342 $ 520,992,953 |
Schedule of costs incurred in oil and natural gas activities | Year Ended December 31, 2021 2020 2019 Acquisition costs Proved properties $ 55,300,252 $ 41,476,733 $ 104,199,579 Unevaluated properties — 74,263,481 110,050,000 Total 55,300,252 115,740,214 214,249,579 Development costs Proved properties — — — Total — — — Total costs incurred on oil, natural gas and NGL activities $ 55,300,252 $ 115,740,214 $ 214,249,579 |
Results of operations from oil, natural gas and natural gas liquids | Year Ended December 31, 2021 2020 2019 Oil, natural gas and NGL revenues $ 175,088,021 $ 92,586,685 $ 107,480,446 Lease bonus and other income 3,319,104 345,771 2,477,145 Production and ad valorem taxes (10,480,481) (6,389,231) (7,719,949) Depreciation and depletion expense (36,797,881) (47,988,796) (52,118,367) Impairment of oil and natural gas properties — (251,558,557) (169,150,255) Marketing and other deductions (12,048,643) (9,376,375) (8,145,397) Results of operations from oil, natural gas and NGLs $ 119,080,120 $ (222,380,503) $ (127,176,377) |
Schedule of net proved oil, natural gas and natural gas liquids reserves and changes | Crude Oil and Natural Gas Condensate Natural Gas Liquids Total (MBbls) (MMcf) (MBbls) (MBOE) Net proved reserves at January 1, 2019 10,795 127,261 5,646 37,651 Revisions of previous estimates (1) 849 25,398 684 5,766 Purchase of minerals in place (2) 1,787 13,129 686 4,661 Production (1,113) (17,046) (561) (4,515) Net proved reserves at December 31, 2019 12,318 148,742 6,455 43,563 Revisions of previous estimates (1) 18 (2,256) (2) (359) Purchase of minerals in place (3) 1,367 15,637 313 4,286 Production (1,409) (17,890) (681) (5,072) Net proved reserves at December 31, 2020 12,294 144,233 6,085 42,418 Revisions of previous estimates (1) 251 24,079 780 5,044 Purchase of minerals in place (4) 1,310 8,537 519 3,252 Production (1,344) (19,085) (715) (5,240) Net proved reserves at December 31, 2021 12,511 157,764 6,669 45,474 Net proved developed reserves December 31, 2019 11,303 141,181 6,079 40,912 December 31, 2020 12,294 144,233 6,085 42,418 December 31, 2021 12,511 157,764 6,669 45,474 Net proved undeveloped reserves December 31, 2019 1,015 7,561 376 2,651 December 31, 2020 — — — — December 31, 2021 — — — — (1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. (2) Includes the acquisition of three packages of mineral and royalty interests for a total of $103.8 million. The first acquisition totaling $58.4 million consists of mineral and royalty interests primarily in the Eagle Ford Shale, Permian Basin, East Texas Region and Appalachia Region. The second acquisition totaling $9.4 million consists of mineral and royalty interests in the Mid-Continent Region. The third acquisition totaling $36.0 million consists of mineral and royalty interests in the Eagle Ford Shale. (3) Includes the acquisition of mineral and royalty interests for a total of $41.5 million. The acquisition consists of mineral and royalty interests primarily in the Delaware Basin, DJ Basin, Haynesville, STACK and Eagle Ford. (4) Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in the Permian Basin, Mid-Continent, Haynesville and other leading U.S. basins. |
Schedule of standardized measure related to proved oil, natural gas and natural gas liquids reserves | The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands): Year Ended December 31, 2021 2020 2019 Future cash inflows $ 1,335,917 $ 705,356 $ 1,025,430 Future production costs (100,947) (55,897) (78,061) Future state margin taxes (42,965) (22,688) (32,377) Future income tax expense — — (33,235) Future net cash flows 1,192,005 626,771 881,757 Less 10% annual discount to reflect timing of cash flows (665,390) (341,775) (481,786) Standard measure of discounted future net cash flows $ 526,615 $ 284,996 $ 399,971 |
Schedule of changes in standardized measure related to proved oil, natural gas and natural gas liquids reserves | Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Standardized measure - beginning of year $ 284,996 $ 399,971 $ 398,367 Sales, net of production costs (152,751) (76,821) (93,942) Net changes of prices and production costs related to future production 225,868 (127,838) (72,875) Revisions of previous quantity estimates, net of related costs 60,517 (2,501) 56,666 Net changes in state margin taxes (8,665) 4,314 191 Net changes in income taxes — 13,480 3,752 Accretion of discount 25,743 38,927 42,808 Purchases of reserves in place 40,545 46,007 59,953 Timing differences and other 50,362 (10,543) 5,051 Standardized measure - end of year $ 526,615 $ 284,996 $ 399,971 |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Details) | 12 Months Ended |
Dec. 31, 2021segment | |
Segment Reporting | |
Number of operating units | 1 |
Number of reporting units | 1 |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -Other Disclosures (Details) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 |
Accounts Receivable | ||
Allowance for doubtful accounts receivable | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property and Equipment (Details) | 12 Months Ended |
Dec. 31, 2021 | |
Minimum | |
Oil and natural gas properties | |
Useful life | 3 years |
Maximum | |
Oil and natural gas properties | |
Useful life | 7 years |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Oil and Natural Gas Properties | |||
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties | $ 0 | $ 0 | $ 0 |
Number of exploratory activities pending determination | 0 | 0 | 0 |
Exploratory costs charged | $ 0 | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Taxes | |||
Uncertain tax positions | $ 0 | $ 0 | $ 0 |
Interest and penalties | $ 0 | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - Sales - Customer - item | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Concentration of Credit Risk | |||
Number of significant purchasers | 1 | ||
Operator 1 | |||
Concentration of Credit Risk | |||
Purchaser percentage | 6.00% | 7.10% | 6.00% |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue from Contracts with Customers (Details) | 12 Months Ended |
Dec. 31, 2021 | |
Minimum | |
Settlement period for certain natural gas and natural gas liquids sales | 1 month |
Maximum | |
Settlement period for certain natural gas and natural gas liquids sales | 4 months |
ACQUISITIONS, JOINT VENTURES _2
ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY - Acquisitions (Details) | Feb. 08, 2022USD ($)$ / sharesshares | Dec. 07, 2021USD ($)item | Jul. 29, 2021$ / sharesshares | Mar. 10, 2021USD ($) | Apr. 17, 2020USD ($)aitemshares | Dec. 12, 2019ashares | Nov. 06, 2019USD ($)a | Mar. 25, 2019ashares | Dec. 31, 2021USD ($)shares | Dec. 31, 2020USD ($) | Jun. 19, 2019USD ($) |
Acquisitions | |||||||||||
Investments | $ | $ 4,738,822 | $ 5,134,951 | |||||||||
Offering costs | $ | $ 930,824 | $ 900,000 | |||||||||
Kimbell Tiger Acquisition Corporation | |||||||||||
Acquisitions | |||||||||||
Joint Venture contributions | $ | $ 14,100,000 | ||||||||||
Common units issued for equity offering (in units) | 23,000,000 | 23,000,000 | 14,100,000 | ||||||||
Share price (in dollar per share) | $ / shares | $ 10 | $ 10 | |||||||||
Warrant share price (in dollar per share) | $ / shares | $ 11.50 | $ 11.50 | |||||||||
Common Units | |||||||||||
Acquisitions | |||||||||||
Common units issued for equity offering (in units) | 4,312,500 | ||||||||||
Underwriters option to purchase additional units | Kimbell Tiger Acquisition Corporation | |||||||||||
Acquisitions | |||||||||||
Common units issued for equity offering (in units) | 3,000,000 | ||||||||||
Nail Bay Royalties | |||||||||||
Acquisitions | |||||||||||
Purchase price cash, gross | $ | $ 500,000 | ||||||||||
Caritas Royalty Fund, LLC | |||||||||||
Acquisitions | |||||||||||
Transaction value of acquisition | $ | $ 54,600,000 | ||||||||||
Number of gross producing wells being operated. | item | 26,000 | ||||||||||
Phillips Acquisition | |||||||||||
Acquisitions | |||||||||||
Gross acres acquired (in acres) | a | 866,528 | ||||||||||
Net royalty acres acquired (in acres) | a | 12,210 | ||||||||||
Phillips Acquisition | OpCo Units | |||||||||||
Acquisitions | |||||||||||
Business Acquisition issuance of common units | 9,400,000 | ||||||||||
Phillips Acquisition | Class B Common Units | |||||||||||
Acquisitions | |||||||||||
Business Acquisition issuance of common units | 9,400,000 | ||||||||||
Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. | |||||||||||
Acquisitions | |||||||||||
Ownership interest (as a percent) | 49.30% | ||||||||||
Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. | Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. | |||||||||||
Acquisitions | |||||||||||
Investments | $ | $ 5,100,000 | $ 5,100,000 | |||||||||
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | |||||||||||
Acquisitions | |||||||||||
Purchase price cash, gross | $ | $ 95,000,000 | ||||||||||
Net royalty acres acquired (in acres) | a | 2,160 | ||||||||||
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | Minimum | |||||||||||
Acquisitions | |||||||||||
The number of operators acquired | item | 90 | ||||||||||
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | OpCo Units | |||||||||||
Acquisitions | |||||||||||
Business Acquisition issuance of common units | 2,497,134 | ||||||||||
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | Common Units | |||||||||||
Acquisitions | |||||||||||
Business Acquisition issuance of common units | 2,224,358 | ||||||||||
Oklahoma Property Acquisition | |||||||||||
Acquisitions | |||||||||||
Purchase price cash, gross | $ | $ 9,900,000 | ||||||||||
Gross acres acquired (in acres) | a | 279,680 | ||||||||||
Net royalty acres acquired (in acres) | a | 186 | ||||||||||
Buckhorn Acquisition | |||||||||||
Acquisitions | |||||||||||
Gross acres acquired (in acres) | a | 86,005 | ||||||||||
Net royalty acres acquired (in acres) | a | 405 | ||||||||||
Buckhorn Acquisition | OpCo Units | |||||||||||
Acquisitions | |||||||||||
Business Acquisition issuance of common units | 2,169,348 | ||||||||||
Buckhorn Acquisition | Class B | |||||||||||
Acquisitions | |||||||||||
Business Acquisition issuance of common units | 2,169,348 |
DERIVATIVES (Details)
DERIVATIVES (Details) | 12 Months Ended | |||
Dec. 31, 2021USD ($)$ / bblbblMMBbls | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jan. 27, 2021USD ($) | |
Derivatives | ||||
Daily oil and natural gas production (as a percent) | 32.00% | |||
Change in fair values of derivative instruments | ||||
Beginning fair value of commodity derivative instruments | $ | $ (6,280,863) | $ 804,501 | $ 4,227,946 | |
Loss on derivative instruments | $ | (41,240,942) | (2,450,541) | (1,732,321) | |
Net cash (received) paid on settlements of derivative instruments | $ | 20,897,159 | (4,634,823) | (1,691,124) | |
Ending fair value of commodity derivative instruments | $ | (26,624,646) | (6,280,863) | 804,501 | |
Assets: | ||||
Current asset | $ | 166,307 | |||
Derivative assets | $ | 1,590,501 | |||
Liabilities: | ||||
Current liability | $ | (24,190,678) | (3,113,178) | ||
Long-term liability | $ | (4,190,776) | (3,167,685) | ||
Derivative assets (liabilities) | $ | (26,624,646) | $ (6,280,863) | $ 804,501 | |
Interest Rate Swap | ||||
Derivatives | ||||
Derivative, Notional Amount | $ | $ 150,000,000 | $ 150,000,000 | ||
Derivative hedging of outstanding debt (as a percent) | 69.00% | |||
Interest rate swap (as a percent) | 3.90% | |||
Commodity derivative contracts | $ | $ 1,800,000 | |||
Liabilities: | ||||
Derivative Asset | $ | $ 1,756,808 | |||
Oil Price Swaps - January 2022 - December 2022 | ||||
Derivatives | ||||
Notional Volumes | bbl | 500,552 | |||
Weighted Average Fixed Price | $ / bbl | 41.86 | |||
Oil Price Swaps - January 2023 - December 2023 | ||||
Derivatives | ||||
Notional Volumes | bbl | 303,411 | |||
Weighted Average Fixed Price | $ / bbl | 59.35 | |||
Natural Gas Price Swaps - January 2022 - December 2022 | ||||
Derivatives | ||||
Notional Volumes | MMBbls | 6,357,449 | |||
Weighted Average Fixed Price | $ / bbl | 2.46 | |||
Natural Gas Price Swaps - January 2023 - December 2023 | ||||
Derivatives | ||||
Notional Volumes | MMBbls | 4,245,899 | |||
Weighted Average Fixed Price | $ / bbl | 2.90 | |||
Minimum | Oil Price Swaps - January 2022 - December 2022 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 35.65 | |||
Minimum | Oil Price Swaps - January 2023 - December 2023 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 53.38 | |||
Minimum | Natural Gas Price Swaps - January 2022 - December 2022 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 2.23 | |||
Minimum | Natural Gas Price Swaps - January 2023 - December 2023 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 2.52 | |||
Maximum | Oil Price Swaps - January 2022 - December 2022 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 46 | |||
Maximum | Oil Price Swaps - January 2023 - December 2023 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 63 | |||
Maximum | Natural Gas Price Swaps - January 2022 - December 2022 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 2.70 | |||
Maximum | Natural Gas Price Swaps - January 2023 - December 2023 | ||||
Derivatives | ||||
Weighted Average Fixed Price | $ / bbl | 3.28 |
FAIR VALUE MEASUREMENTS (Detail
FAIR VALUE MEASUREMENTS (Details) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 |
Commodity Derivative contract | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative contracts liabilities | $ (28,381,454) | $ (6,280,863) |
Commodity Derivative contract | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative contracts liabilities | (28,381,454) | $ (6,280,863) |
Interest Rate Swap | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivative contracts | 1,800,000 | |
Derivative contracts assets | 1,756,808 | |
Interest Rate Swap | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative contracts assets | $ 1,756,808 |
OIL AND NATURAL GAS PROPERTIE_2
OIL AND NATURAL GAS PROPERTIES (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
OIL AND NATURAL GAS PROPERTIES | |||
Proved properties | $ 1,051,111,311 | $ 923,413,606 | |
Unevaluated properties | 153,284,173 | 225,681,626 | |
Less: accumulated depreciation, depletion, and impairment | (663,603,142) | (628,102,279) | |
Total oil and natural gas properties, net | 540,792,342 | 520,992,953 | |
Transfer to full cost pool | 48,600,000 | ||
Percent of proved undeveloped reserves of estimated proved reserves (as a percent) | 6.10% | ||
Impairment of oil and natural gas properties | $ 0 | $ 251,558,557 | $ 169,150,255 |
LEASES (Details)
LEASES (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
LEASES | |||
Operating lease weighted average remaining lease term | 7 years 4 months 6 days | ||
Operating lease weighted average discount rate (as a percent) | 6.75% | ||
Operating lease expense | $ 400,000 | $ 500,000 | $ 300,000 |
2022 | 486,045 | ||
2023 | 487,787 | ||
2024 | 488,725 | ||
2025 | 497,033 | ||
2026 | 507,648 | ||
Thereafter | 1,219,267 | ||
Total operating leases | 3,686,505 | ||
Less Imputed Interest | (823,006) | ||
Total | $ 2,863,499 |
LONG-TERM DEBT (Details)
LONG-TERM DEBT (Details) - USD ($) | Dec. 08, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Nov. 01, 2021 | Dec. 07, 2020 | Feb. 08, 2017 |
Long-term debt | |||||||
Amortization of Debt Issuance Costs | $ 1,556,769 | $ 1,108,685 | $ 1,050,278 | ||||
Borrowings of debt | 136,565,769 | 162,614,665 | $ 12,825,933 | ||||
Repayment of debt | 91,000,000 | 91,200,000 | |||||
Revolving credit facility | |||||||
Long-term debt | |||||||
Revolving credit facility maximum borrowings | $ 265,000,000 | $ 225,000,000 | |||||
Revolving credit facility increased maximum borrowing capacity if certain conditions are met | $ 500,000,000 | ||||||
Amortization of Debt Issuance Costs | $ 500,000 | ||||||
Revolving credit facility outstanding | $ 217,100,000 | ||||||
Floor margin | 0.25% | ||||||
Permitted numerator subjected to cash | $ 25,000,000 | ||||||
Interest rate on outstanding borrowings (as a percent) | 3.86% | ||||||
Borrowing base | $ 265,000,000 | $ 275,000,000 | |||||
Amount of applicable margin increase for each applicable level (as a percent) | 1.00% | ||||||
Commitment fees (as a percent) | 0.50% | ||||||
Borrowings of debt | $ 136,600,000 | ||||||
Repayment of debt | $ 91,000,000 | ||||||
Revolving credit facility | LIBOR | |||||||
Long-term debt | |||||||
Variable rate | LIBOR | ||||||
Margin (as a percent) | 3.75% | ||||||
Revolving credit facility | Prime | |||||||
Long-term debt | |||||||
Margin (as a percent) | 2.75% | ||||||
Revolving credit facility | Maximum | |||||||
Long-term debt | |||||||
Debt to EBITDAX ratio | 400.00% | 350.00% | |||||
Revolving credit facility | Maximum | LIBOR | |||||||
Long-term debt | |||||||
Margin (as a percent) | 4.00% | ||||||
Revolving credit facility | Maximum | Prime | |||||||
Long-term debt | |||||||
Margin (as a percent) | 3.00% | ||||||
Revolving credit facility | Minimum | |||||||
Long-term debt | |||||||
Debt to EBITDAX ratio | 350.00% | ||||||
Current assets to current liabilities ratio | 100.00% | ||||||
Revolving credit facility | Minimum | LIBOR | |||||||
Long-term debt | |||||||
Margin (as a percent) | 3.00% | ||||||
Revolving credit facility | Minimum | Prime | |||||||
Long-term debt | |||||||
Margin (as a percent) | 2.00% |
PREFERRED UNITS - Other (Detail
PREFERRED UNITS - Other (Details) - USD ($) | Dec. 07, 2021 | Jul. 07, 2021 | Feb. 12, 2020 | Jul. 31, 2018 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Preferred units | |||||||
Temporary equity, outstanding (in units) | 0 | 55,000 | |||||
Series A preferred units deemed distributions | $ 11,249,969 | $ 7,810,588 | $ 13,878,336 | ||||
Series A Preferred Units | |||||||
Preferred units | |||||||
Redemption of Series A preferred units | 25,000 | 30,000 | 55,000 | 55,000 | |||
Percentage of Series A preferred units redeemed | 55.00% | 50.00% | |||||
Unit price (in dollars per unit) | $ 1,240.25 | $ 1,202.51 | $ 1,110.72 | ||||
Series A preferred units redemption price | $ 31,000,000 | $ 36,100,000 | $ 61,100,000 | ||||
Deemed distribution amount | $ 5,700,000 | ||||||
Temporary equity, outstanding (in units) | 25,000 | ||||||
Series A preferred units deemed distributions | $ 3,800,000 | ||||||
Series A Preferred Units | Minimum | |||||||
Preferred units | |||||||
Percent of consideration transferred to carrying value of units (as a percent) | 50.00% | ||||||
Percent of consideration transferred to original intrinsic value of units (as a percent) | 50.00% | ||||||
Series A Preferred Stock | |||||||
Preferred units | |||||||
Series A preferred units deemed distributions | $ 3,600,000 | ||||||
Affiliates of Apollo Capital Management, L.P. | |||||||
Preferred units | |||||||
Series A preferred units issued | 110,000 | ||||||
Share price (in dollars per unit) | $ 1,000 | ||||||
Proceeds from the issuance of preferred units | $ 110,000,000 | ||||||
Distribution rate (as a percent) | 7.00% | ||||||
The period after issuance securities become convertible | 2 years | ||||||
Discount rate to the issue price (as a percent) | $ 30 | ||||||
Percent of redemption price exceeding invested capital for the Partnership to initiate redemption (as a percent) | 120.00% | ||||||
Minimum IRR prior to the fifth anniversary of Series A Issuance Date (as a percent) | 13.00% | ||||||
Minimum IRR on or after the fifth anniversary of Series A Issuance Date (as a percent) | 14.00% | ||||||
Minimum IRR on or after the sixth anniversary of Series A Issuance Date (as a percent) | 15.00% |
PREFERRED UNITS - Rollforward (
PREFERRED UNITS - Rollforward (Details) - Series A Preferred Units - shares | Dec. 07, 2021 | Jul. 07, 2021 | Feb. 12, 2020 | Dec. 31, 2021 |
Preferred units rollforward | ||||
Balance at beginning of period | 55,000 | |||
Redemption of Series A preferred units | (25,000) | (30,000) | (55,000) | (55,000) |
UNITHOLDERS' EQUITY AND PARTN_3
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||
Nov. 30, 2021 | Jan. 31, 2020 | Dec. 31, 2021 | Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | |
Common units | ||||||||||||||||
Units issued (in units) | 47,162,773 | 38,918,689 | 47,162,773 | 38,918,689 | ||||||||||||
Units outstanding (in units) | 47,162,773 | 38,918,689 | 47,162,773 | 38,918,689 | ||||||||||||
Repayment of debt | $ 91,000,000 | $ 91,200,000 | ||||||||||||||
Capital rollforward | ||||||||||||||||
Unitholders' capital, beginning balance (in units) | 38,918,689 | 38,918,689 | ||||||||||||||
Unitholders' capital, ending balance (in units) | 47,162,773 | 38,918,689 | 47,162,773 | 38,918,689 | ||||||||||||
Cash distributions declared and paid (in dollars per unit) | $ 0.37 | $ 0.37 | $ 0.31 | $ 0.27 | $ 0.19 | $ 0.19 | $ 0.13 | $ 0.17 | $ 0.38 | $ 0.42 | $ 0.39 | $ 0.37 | ||||
Common Units | ||||||||||||||||
Common units | ||||||||||||||||
Units issued (in units) | 47,162,773 | 47,162,773 | ||||||||||||||
Units outstanding (in units) | 47,162,773 | 38,918,689 | 47,162,773 | 38,918,689 | ||||||||||||
Capital rollforward | ||||||||||||||||
Unitholders' capital, beginning balance (in units) | 38,918,689 | 38,918,689 | ||||||||||||||
Common units issued for equity offering (in units) | 4,312,500 | |||||||||||||||
Conversion of Class B Units (in units) | 3,168,202 | |||||||||||||||
Common units issued under the LTIP (in units) | 936,567 | |||||||||||||||
Restricted units repurchased for tax withholding (in units) | (173,185) | |||||||||||||||
Unitholders' capital, ending balance (in units) | 47,162,773 | 38,918,689 | 47,162,773 | 38,918,689 | ||||||||||||
Class B | ||||||||||||||||
Common units | ||||||||||||||||
Units outstanding (in units) | 17,611,579 | 20,779,781 | 17,611,579 | 20,779,781 | ||||||||||||
Capital rollforward | ||||||||||||||||
Unitholders' capital, beginning balance (in units) | 20,779,781 | 20,779,781 | ||||||||||||||
Conversion of Class B Units (in units) | (3,168,202) | |||||||||||||||
Unitholders' capital, ending balance (in units) | 17,611,579 | 20,779,781 | 17,611,579 | 20,779,781 | ||||||||||||
Cash distributions (as a percent) | 2.00% | |||||||||||||||
Additional consideration paid per unit (in dollars per unit) | $ 0.05 | |||||||||||||||
Public Offering | ||||||||||||||||
Common units | ||||||||||||||||
Units issued (in units) | 4,312,500 | 5,000,000 | ||||||||||||||
Proceeds from equity offering | $ 57,700,000 | $ 73,600,000 | ||||||||||||||
Repayment of debt | $ 56,000,000 | $ 70,000,000 | ||||||||||||||
Underwriters option to purchase additional units | ||||||||||||||||
Common units | ||||||||||||||||
Units outstanding (in units) | 750,000 | |||||||||||||||
Capital rollforward | ||||||||||||||||
Unitholders' capital, ending balance (in units) | 750,000 |
EARNINGS (LOSS) PER COMMON UN_3
EARNINGS (LOSS) PER COMMON UNIT (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Earnings per unit | |||
Net income (loss) attributable to common units | $ 22,615,021 | $ (167,350,893) | $ (83,032,282) |
Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interest | 8,496,104 | (96,642,334) | (89,148,428) |
Diluted net income (loss) attributable to common units | $ 31,111,125 | $ (167,350,893) | $ (83,032,282) |
Weighted average number of common units outstanding Basic (in units) | 40,400,907 | 34,530,398 | 21,192,714 |
Weighted average number of common units outstanding Diluted (in units) | 60,957,824 | 34,530,398 | 21,192,714 |
Net income (loss) attributable to common units per unit (basic) | $ 0.56 | $ (4.85) | $ (3.92) |
Net income (loss) attributable to common units per unit (diluted) | $ 0.51 | $ (4.85) | $ (3.92) |
Restricted Units | |||
Earnings per unit | |||
Weighted average number of common units outstanding (in units) | 1,717,310 | ||
Anti-dilutive options outstanding | 1,276,546 | 739,479 | |
Unvested Restricted Units | |||
Earnings per unit | |||
Weighted average number of common units outstanding (in units) | 1,717,310 | ||
Class B | |||
Earnings per unit | |||
Weighted average number of common units outstanding (in units) | 18,839,607 |
UNIT-BASED COMPENSATION (Detail
UNIT-BASED COMPENSATION (Details) - Long-Term Incentive Plan - $ / shares | Sep. 23, 2018 | Dec. 31, 2021 | Dec. 31, 2020 |
Unit-based compensation | |||
Additional common units authorized for issuance | 4,541,600 | ||
Vesting period | 3 years | ||
First Anniversary | |||
Unit-based compensation | |||
Vesting percent | 33.30% | ||
Second Anniversary | |||
Unit-based compensation | |||
Vesting percent | 33.30% | ||
Third Anniversary | |||
Unit-based compensation | |||
Vesting percent | 33.30% | ||
Restricted Units | |||
Unvested Units | |||
Unvested at beginning of period (in units) | 1,276,546 | ||
Awarded (in units) | 936,567 | ||
Vesting (in units) | (652,214) | ||
Unvested at end of period (in units) | 1,560,899 | 1,276,546 | |
Unvested Weighted Average Grant-Date Fair Value | |||
Unvested at beginning of period (in dollars per unit) | $ 13.604 | ||
Awarded (in dollars per unit) | 10.350 | ||
Vesting (in dollars per unit) | 14.905 | ||
Unvested at end of period (in dollars per unit) | $ 11.108 | $ 13.604 | |
Weighted Average Remaining Contractual Term | |||
Unvested contractual term, at end of period | 1 year 9 months 9 days | 1 year 9 months 13 days |
INCOME TAXES - (Details)
INCOME TAXES - (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
INCOME TAXES | |||
Texas franchise tax (as a percent) | 0.75% | ||
Effective income tax rate (as a percent) | 0.17% | ||
(Benefit from) provision for income taxes | $ (74,100) | $ 885,193 | $ (899,425) |
INCOME TAXES - Provision (Detai
INCOME TAXES - Provision (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current | |||
Federal | $ 69,067 | $ (812,913) | $ 812,913 |
State | 5,033 | (72,280) | 86,512 |
Total Current | 74,100 | (885,193) | 899,425 |
Deferred | |||
Provision for (benefit from) income taxes | $ 74,100 | $ (885,193) | $ 899,425 |
INCOME TAXES - Reconciliation (
INCOME TAXES - Reconciliation (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Reconciliation of the provision for income taxes at statutory rates to the provision for income taxes at the effective tax rate | |||
Net income (loss) before taxes | $ 42,511,974 | $ (256,975,963) | $ (157,308,520) |
Statutory rate (as a percent) | 21.00% | 21.00% | 21.00% |
Income tax provision (benefit) computed at statutory rate | $ 8,927,515 | $ (53,964,952) | $ (33,034,789) |
State income taxes | 5,033 | (72,280) | 72,280 |
Non-controlling interest | (1,788,347) | 20,294,890 | 18,721,170 |
(Income) loss at OpCo | (7,139,168) | 33,670,062 | 15,130,685 |
Change in valuation allowance - federal | (363,132) | (749,866) | 80,520 |
Change in valuation allowance - state | (40,626) | 168,393 | (70,441) |
Other, net | 472,825 | (231,440) | |
Provision for (benefit from) income taxes | $ 74,100 | $ (885,193) | $ 899,425 |
INCOME TAXES - Deferred Taxes (
INCOME TAXES - Deferred Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Deferred tax asset | |||
Outside basis in OpCo | $ 6,641,452 | $ 17,624,909 | $ 20,050,732 |
Federal tax loss carryforwards | 12,296,282 | 1,675,957 | |
State tax loss carryforwards | 1,789,961 | 238,559 | |
Deferred tax assets | 20,727,695 | 19,539,425 | 20,050,732 |
Valuation allowance | (20,727,695) | (19,539,425) | (20,050,732) |
Deferred tax liability | |||
Outside basis investment in operating company valuation allowance | 20,700,000 | ||
Uncertain tax positions | $ 0 | $ 0 | $ 0 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) | Feb. 08, 2022 | Jul. 29, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Related Party Transactions | |||||
Offering costs | $ 930,824 | $ 900,000 | |||
Kimbell Tiger Acquisition Corporation | |||||
Related Party Transactions | |||||
Common units issued for equity offering (in units) | 23,000,000 | 23,000,000 | 14,100,000 | ||
Share price (in dollar per share) | $ 10 | $ 10 | |||
Underwritten Public Offering | Kimbell Tiger Acquisition Corporation | |||||
Related Party Transactions | |||||
Common units issued for equity offering (in units) | 3,000,000 | ||||
BJF Royalties | |||||
Related Party Transactions | |||||
Payments made to related parties | $ 0 | ||||
K3 Royalties | |||||
Related Party Transactions | |||||
Payments made to related parties | 120,000 | ||||
Nail Bay Royalties | |||||
Related Party Transactions | |||||
Payments made to related parties | 301,314 | ||||
Duncan Management | |||||
Related Party Transactions | |||||
Payments made to related parties | 548,480 | ||||
Director And Officer Insurance To Partnership At Higginbotham Insurance Financial Services | |||||
Related Party Transactions | |||||
Related Party Transaction, Amounts of Transaction | 22,160 | $ 20,160 | $ 18,900 | ||
Related Party Transactions, Annual Insurance Premium Expense | $ 555,640 | $ 440,160 | $ 350,000 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
COMMITMENTS AND CONTINGENCIES. | |||
2022 | $ 486,045 | ||
2023 | 487,787 | ||
2024 | 488,725 | ||
2025 | 497,033 | ||
2026 | 507,648 | ||
Thereafter | 1,219,267 | ||
Total operating leases | 3,686,505 | ||
Operating lease liabilities, excluding current portion | 2,561,274 | $ 2,848,452 | |
Operating Lease, Expense | $ 400,000 | $ 500,000 | $ 300,000 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - USD ($) | Feb. 24, 2022 | Feb. 08, 2022 | Feb. 07, 2022 | Jan. 28, 2022 | Jan. 27, 2022 | Jan. 21, 2022 | Jan. 14, 2022 | Jul. 29, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 08, 2020 | Dec. 07, 2020 |
Subsequent events | |||||||||||||
Distributions on Series A redeemable preferred units | $ 2,800,012 | $ 4,812,509 | $ 7,700,000 | ||||||||||
Distributions to Class B unitholders | 76,780 | 91,869 | $ 94,429 | ||||||||||
Common units issued for equity offering | $ 57,522,440 | $ 73,601,668 | |||||||||||
Common Units | |||||||||||||
Subsequent events | |||||||||||||
Common units issued for equity offering (in units) | 4,312,500 | ||||||||||||
Subsequent Event | Class B Common Units | |||||||||||||
Subsequent events | |||||||||||||
Distributions to Class B unitholders | $ 17,610 | ||||||||||||
Percentage Of Respective Class Contribution Made | 2.00% | ||||||||||||
Subsequent Event | Common Units | |||||||||||||
Subsequent events | |||||||||||||
Cash distributions declared (in dollars per unit) | $ 0.37 | ||||||||||||
Subsequent Event | Certain Employees, Directors and Consultants | |||||||||||||
Subsequent events | |||||||||||||
Cash bonuses awarded | $ 2,200,000 | ||||||||||||
Subsequent Event | Certain Employees, Directors and Consultants | Restricted Units | |||||||||||||
Subsequent events | |||||||||||||
Units issued for bonus compensation | 963,835 | ||||||||||||
Revolving credit facility | |||||||||||||
Subsequent events | |||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 265,000,000 | $ 225,000,000 | |||||||||||
Revolving credit facility | Subsequent Event | |||||||||||||
Subsequent events | |||||||||||||
Draw downs | $ 5,000,000 | $ 1,200,000 | $ 12,900,000 | ||||||||||
Kimbell Tiger Acquisition Corporation | |||||||||||||
Subsequent events | |||||||||||||
Common units issued for equity offering (in units) | 23,000,000 | 23,000,000 | 14,100,000 | ||||||||||
Share price (in dollar per share) | $ 10 | $ 10 | |||||||||||
Kimbell Tiger Acquisition Corporation | Subsequent Event | |||||||||||||
Subsequent events | |||||||||||||
Common units issued for equity offering (in units) | 23,000,000 | ||||||||||||
Share price (in dollar per share) | $ 10 | ||||||||||||
Underwritten Public Offering | Kimbell Tiger Acquisition Corporation | |||||||||||||
Subsequent events | |||||||||||||
Common units issued for equity offering (in units) | 3,000,000 | ||||||||||||
Underwritten Public Offering | Kimbell Tiger Acquisition Corporation | Subsequent Event | |||||||||||||
Subsequent events | |||||||||||||
Common units issued for equity offering (in units) | 3,000,000 |
SUPPLEMENTAL OIL AND GAS RESE_3
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Other Disclosures (Details) | 12 Months Ended | ||
Dec. 31, 2021USD ($)segment | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | |||
Number of reporting segments | segment | 1 | ||
Oil, natural gas and NGL interests | |||
Proved properties | $ 1,051,111,311 | $ 923,413,606 | |
Unevaluated properties | 153,284,173 | 225,681,626 | |
Total oil, natural gas and NGL interest | 1,204,395,484 | 1,149,095,232 | |
Accumulated depreciation, depletion and impairment | (663,603,142) | (628,102,279) | |
Net oil, natural gas and NGL interests capitalized | 540,792,342 | 520,992,953 | |
Acquisition costs | |||
Proved properties | 55,300,252 | 41,476,733 | $ 104,199,579 |
Unevaluated properties | 74,263,481 | 110,050,000 | |
Total | 55,300,252 | 115,740,214 | 214,249,579 |
Developed costs | |||
Total costs incurred on oil, natural gas and NGL activities | 55,300,252 | 115,740,214 | 214,249,579 |
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities | |||
Oil, natural gas and NGL revenue | 175,088,021 | 92,586,685 | 107,480,446 |
Lease bonus and other income | 3,319,104 | 345,771 | 2,477,145 |
Production and ad valorem taxes | (10,480,481) | (6,389,231) | (7,719,949) |
Depreciation and depletion expense | (36,797,881) | (47,988,796) | (52,118,367) |
Impairment of oil and natural properties | (251,558,557) | (169,150,255) | |
Marketing and other deductions | (12,048,643) | (9,376,375) | (8,145,397) |
Results of operations form oil, natural gas and NGLs | $ 119,080,120 | $ (222,380,503) | $ (127,176,377) |
SUPPLEMENTAL OIL AND GAS RESE_4
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Proved Oil, Natural Gas and Natural Liquids Reserve Quantities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021USD ($)MBblsMMcf | Dec. 31, 2020USD ($)MMcfMBbls | Dec. 31, 2019USD ($)itemMMcfMBbls | |
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | 42,418 | 43,563 | 37,651 |
Revisions of previous estimates | 5,044 | (359) | 5,766 |
Purchase of minerals in place | 3,252 | 4,286 | 4,661 |
Production | (5,240) | (5,072) | (4,515) |
Net proved reserves at end of period | 45,474 | 42,418 | 43,563 |
Net Proved Developed Reserves | 45,474 | 42,418 | 40,912 |
Net Proved Undeveloped Reserves | 2,651 | ||
Crude Oil and Condensate | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | 12,294 | 12,318 | 10,795 |
Revisions of previous estimates | 251 | 18 | 849 |
Purchase of minerals in place | 1,310 | 1,367 | 1,787 |
Production | (1,344) | (1,409) | (1,113) |
Net proved reserves at end of period | 12,511 | 12,294 | 12,318 |
Net Proved Developed Reserves | 12,511 | 12,294 | 11,303 |
Net Proved Undeveloped Reserves | 1,015 | ||
Natural Gas | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | MMcf | 144,233 | 148,742 | 127,261 |
Revisions of previous estimates | MMcf | 24,079 | (2,256) | 25,398 |
Purchase of minerals in place | MMcf | 8,537 | 15,637 | 13,129 |
Production | MMcf | (19,085) | (17,890) | (17,046) |
Net proved reserves at end of period | MMcf | 157,764 | 144,233 | 148,742 |
Net Proved Developed Reserves | MMcf | 157,764 | 144,233 | 141,181 |
Net Proved Undeveloped Reserves | MMcf | 7,561 | ||
Natural Gas Liquids | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | 6,085 | 6,455 | 5,646 |
Revisions of previous estimates | 780 | (2) | 684 |
Purchase of minerals in place | 519 | 313 | 686 |
Production | (715) | (681) | (561) |
Net proved reserves at end of period | 6,669 | 6,085 | 6,455 |
Net Proved Developed Reserves | 6,669 | 6,085 | 6,079 |
Net Proved Undeveloped Reserves | 376 | ||
Permian Basis, Haynesville Shale, Mid-Continent Area, Appalachia Region and Eagle Ford Shale | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 55.3 | $ 103.8 | |
Number of packages of diverse mineral and royalty interests acquired | item | 3 | ||
Permian Basin And Eagle Ford Shale And East Texas Region And Appalachia Region [Member] | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 58.4 | ||
Permian Basin Mid-Continent Region [Member] | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | 9.4 | ||
Permian Basin And Eagle Ford Shale Region [Member] | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 36 | ||
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 41.5 |
SUPPLEMENTAL OIL AND GAS RESE_5
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Standardized Measure (Details) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Standardized Measure | ||||
Future cash inflows | $ 1,335,917 | $ 705,356 | $ 1,025,430 | |
Future production costs | (100,947) | (55,897) | (78,061) | |
Future state margin taxes | (42,965) | (22,688) | (32,377) | |
Future income tax expense | (33,235) | |||
Future net cash flows | 1,192,005 | 626,771 | 881,757 | |
Less 10% annual discount to reflect timing of cash flows | (665,390) | (341,775) | (481,786) | |
Standard measure of discounted future net cash flows | $ 526,615 | $ 284,996 | $ 399,971 | $ 398,367 |
SUPPLEMENTAL OIL AND GAS RESE_6
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Average Market Prices (Details) - $ / bbl | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Crude Oil and Condensate | |||
Average Sales Prices | |||
Average sales prices | 66.56 | 39.57 | 55.69 |
Natural Gas | |||
Average Sales Prices | |||
Average sales prices | 3.60 | 1.99 | 2.58 |
SUPPLEMENTAL OIL AND GAS RESE_7
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Changes in Standardized Measure (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in Standardized Measure | |||
Standardized measure - beginning of year | $ 284,996 | $ 399,971 | $ 398,367 |
Sales, net of production costs | (152,751) | (76,821) | (93,942) |
Net changes of prices and production costs related to future production | 225,868 | (127,838) | (72,875) |
Revisions of previous quantity estimates, net of related costs | 60,517 | (2,501) | 56,666 |
Net changes in state margin taxes | (8,665) | 4,314 | 191 |
Net changes in income taxes | 13,480 | 3,752 | |
Accretion of discount | 25,743 | 38,927 | 42,808 |
Purchases of reserves in place | 40,545 | 46,007 | 59,953 |
Timing differences and other | 50,362 | (10,543) | 5,051 |
Standardized measure - end of year | $ 526,615 | $ 284,996 | $ 399,971 |