KRP 10-Q
Kimbell Royalty Partners, LP (KRP)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended OR | |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to | |
Commission file number:
(Exact name of registrant as specified in its charter)
| 1311 |
|
(
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: | Trading symbol(s) | Name of exchange on which registered: |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
As of May 2, 2025, the registrant had outstanding
KIMBELL ROYALTY PARTNERS, LP
FORM 10-Q
TABLE OF CONTENTS
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PART I – FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)
KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, | December 31, | |||||
2025 | 2024 | |||||
ASSETS | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | | $ | | ||
Oil, natural gas and NGL receivables | | | ||||
Derivative assets | — | | ||||
Accounts receivable and other current assets | | | ||||
Total current assets | | | ||||
Property and equipment, net | | | ||||
Oil and natural gas properties | ||||||
Oil and natural gas properties, using full cost method of accounting ($ | | | ||||
Less: accumulated depreciation, depletion and impairment | ( | ( | ||||
Total oil and natural gas properties, net | | | ||||
Right-of-use assets, net | | | ||||
Derivative assets | — | | ||||
Loan origination costs, net | | | ||||
Total assets | $ | | $ | | ||
LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY | ||||||
Current liabilities | ||||||
Accounts payable | $ | | $ | | ||
Other current liabilities | | | ||||
Derivative liabilities | | | ||||
Total current liabilities | | | ||||
Operating lease liabilities, excluding current portion | | | ||||
Derivative liabilities | | | ||||
Long-term debt | | | ||||
Other liabilities | | | ||||
Total liabilities | | | ||||
Commitments and contingencies (Note 16) | ||||||
Mezzanine equity: | ||||||
Series A preferred units ( | | | ||||
Kimbell Royalty Partners, LP unitholders' equity: | ||||||
Common units ( | | | ||||
Class B units ( | | | ||||
Total Kimbell Royalty Partners, LP unitholders' equity | | | ||||
Non-controlling interest in OpCo | | | ||||
Total unitholders' equity | | | ||||
Total liabilities, mezzanine equity and unitholders' equity | $ | | $ | | ||
The accompanying notes are an integral part of these consolidated financial statements.
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended March 31, | ||||||
2025 | 2024 | |||||
Revenue | ||||||
Oil, natural gas and NGL revenues | $ | | $ | | ||
Lease bonus and other income | | | ||||
Loss on commodity derivative instruments, net | ( | ( | ||||
Total revenues | | | ||||
Costs and expenses | ||||||
Production and ad valorem taxes | | | ||||
Depreciation and depletion expense | | | ||||
Impairment of oil and natural gas properties | — | | ||||
Marketing and other deductions | | | ||||
General and administrative expense | | | ||||
Total costs and expenses | | | ||||
Operating income | | | ||||
Other expense | ||||||
Interest expense | ( | ( | ||||
Other expense | ( | — | ||||
Net income before income taxes | | | ||||
Income tax expense | | | ||||
Net income | | | ||||
Distribution and accretion on Series A preferred units | ( | ( | ||||
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests | ( | ( | ||||
Distribution on Class B units | ( | ( | ||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | | $ | | ||
Net income per unit attributable to common units of Kimbell Royalty Partners, LP | ||||||
Basic | $ | | $ | | ||
Diluted | $ | | $ | | ||
Weighted average number of common units outstanding | ||||||
Basic | | | ||||
Diluted | | | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY
(Unaudited)
Three Months Ended March 31, 2025 | ||||||||||||||||||
Non-controlling | ||||||||||||||||||
| Common Units |
| Amount |
| Class B Units |
| Amount | Interest | Total | |||||||||
Balance at January 1, 2025 | | $ | | | $ | | $ | | $ | | ||||||||
Common units issued for equity offering | | | — | — | — | | ||||||||||||
Unit-based compensation | | | — | — | — | | ||||||||||||
Restricted units repurchased for tax withholding | ( | ( | — | — | — | ( | ||||||||||||
Conversion of Class B units to common units | | | ( | ( | ( | ( | ||||||||||||
Forfeiture of restricted units | ( | ( | — | — | — | ( | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution and accretion on Series A preferred units | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Change in ownership of consolidated subsidiaries, net | — | ( | — | — | | — | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at March 31, 2025 | | $ | | | $ | | $ | | $ | | ||||||||
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY — (Continued)
(Unaudited)
Three Months Ended March 31, 2024 | ||||||||||||||||||
Non-controlling | ||||||||||||||||||
| Common Units |
| Amount |
| Class B Units |
| Amount | Interest | Total | |||||||||
Balance at January 1, 2024 | | $ | | | $ | | $ | | $ | | ||||||||
Restricted units repurchased for tax withholding | ( | ( | — | — | — | ( | ||||||||||||
Unit-based compensation | | | — | — | — | | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution and accretion on Series A preferred units | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Change in ownership of consolidated subsidiaries, net | — | | — | — | ( | — | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at March 31, 2024 | | $ | | | $ | | $ | | $ | | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31, | ||||||
2025 |
| 2024 | ||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||
Net income | $ | | $ | | ||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depreciation and depletion expense | | | ||||
Impairment of oil and natural gas properties | — | | ||||
Amortization of right-of-use assets | | | ||||
Amortization of loan origination costs | | | ||||
Unit-based compensation | | | ||||
Forfeiture of restricted units | ( | — | ||||
Loss on derivative instruments, net of settlements | | | ||||
Changes in operating assets and liabilities: | ||||||
Oil, natural gas and NGL receivables | ( | | ||||
Accounts receivable and other current assets | | ( | ||||
Accounts payable | ( | | ||||
Other current liabilities | | ( | ||||
Operating lease liabilities | ( | ( | ||||
Net cash provided by operating activities | | | ||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||
Purchases of property and equipment | ( | ( | ||||
Proceeds from sale of property and equipment | | — | ||||
Purchase of oil and natural gas properties | ( | ( | ||||
Net cash used in investing activities | ( | ( | ||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||
Proceeds from equity offering, net of issuance costs | | — | ||||
Redemption of Class B contributions on converted units | ( | — | ||||
Distribution to common unitholders | ( | ( | ||||
Distribution to OpCo unitholders | ( | ( | ||||
Distribution on Series A preferred units | ( | ( | ||||
Distribution on Class B units | ( | ( | ||||
Borrowings on long-term debt | | | ||||
Repayments on long-term debt | ( | ( | ||||
Payment of loan origination costs | — | ( | ||||
Restricted units repurchased for tax withholding | ( | ( | ||||
Net cash provided by (used in) financing activities | | ( | ||||
NET INCREASE IN CASH AND CASH EQUIVALENTS | | | ||||
CASH AND CASH EQUIVALENTS, beginning of period | | | ||||
CASH AND CASH EQUIVALENTS, end of period | $ | | $ | | ||
Supplemental cash flow information: | ||||||
Cash paid for interest | $ | | $ | | ||
Non-cash investing and financing activities: | ||||||
Deemed distribution to Series A preferred units | $ | | $ | | ||
Distribution on Series A preferred units in accounts payable | $ | | $ | | ||
Recognition of tenant improvement asset | $ | | $ | | ||
Right-of-use assets obtained in exchange for operating lease liabilities | $ | | $ | — | ||
The accompanying notes are an integral part of these consolidated financial statements.
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Unless the context otherwise requires, 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” or “OpCo” 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, 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. 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 accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). As a result, the accompanying unaudited interim consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2024 (the “2024 Form 10-K”), which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the General Partner, the unaudited interim consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP and all adjustments are of a normal recurring nature. The accompanying unaudited interim consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries. All material intercompany balances and transactions are eliminated in consolidation. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.
Use of Estimates
Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates.
Segment Reporting
The Partnership has one business activity as the owner of mineral and royalty interests and operates in a operating and segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker (the “CODM”) in deciding how to allocate resources and assess performance. The segment participates in activities and derives revenue as described in the organization section on a consolidated basis. The Partnership’s CODM is our Chief Operating Officer.
The CODM assesses performance for the segment and decides how to allocate resources based on net income presented on a consolidated basis, for purposes of allocating resources and evaluating financial performance as presented
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on the consolidated statement of operations. The CODM uses this measure in the annual budgeting and monthly forecasting process and to evaluate income generated from segment assets to distribute cash to unitholders and deciding whether to reinvest profits for new or existing mineral and royalty interest through acquisitions or organic growth. The measure of segment assets is reported on the balance sheet as total consolidated assets. The accounting policies of the segment are the same as those described in the summary of significant accounting policies.
Significant segment expenses of the Partnership include production and ad valorem taxes, depreciation and depletion expense, impairment of oil and natural gas properties, marketing and other deductions, general and administrative expense and interest expense. Other segment items included in net income are income tax expenses and other income (expense) line items. All significant segment expenses and other segment items are presented individually in the consolidated statements of operations.
Global Conflicts and Uncertainties
In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas and is still active. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. In January 2025, Israel and Hamas agreed to a ceasefire deal, however, in March 2025 Israel carried out air strikes against Hamas, suggesting there is no indication on the extent of the ceasefire. These conflicts and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, the Partnership has not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, the Partnership will continue to monitor for events that could materially impact them.
President Trump has executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of commodities, increase the price of supplies and raw materials that we rely on, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our operations and expenses.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant Accounting Policies
For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s 2024 Form 10-K. There have been no substantial changes in such policies or the application of such policies during the three months ended March 31, 2025.
Recently Issued Accounting Pronouncements
In December 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. For entities other than public business entities, the amendments are effective for annual periods beginning after December 15, 2025, with early adoption permitted. The Partnership is currently evaluating the impact of the adoption of this update but does not believe it will have a material impact on its financial position, results of operations or liquidity.
In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40).” The amendments in this update apply to all public business entities. The amendments in this update are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The amendments in this update should be applied either (1) prospectively to financial statements issued for reporting periods after the effective
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date of this Update or (2) retrospectively to any or all prior periods presented in the financial statements. The Partnership is currently evaluating the impact of the adoption of this update but does not believe it will have a material impact on its financial position, results of operations or liquidity.
NOTE 3—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.
The following table disaggregates the Partnership’s oil, natural gas and NGL revenues for the following periods:
Three Months Ended March 31, | ||||||
2025 |
| 2024 | ||||
Oil revenue | $ | | $ | | ||
Natural gas revenue | | | ||||
NGL revenue | | | ||||
Total Oil, natural gas and NGL revenues | $ | | $ | | ||
NOTE 4—ACQUISITIONS
Acquisitions
On January 17, 2025, the Partnership completed the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in a transaction valued at approximately $
NOTE 5—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.
As of March 31, 2025, 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’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 scheduled trading day of the first nearby month futures contract corresponding to the relevant contract period. Settlement for oil
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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 unaudited interim consolidated statements of operations.
The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in the fair value consisted of the following:
Three Months Ended March 31, | ||||||
2025 | 2024 | |||||
Beginning fair value of derivative instruments | $ | | $ | | ||
Loss on commodity derivative instruments, net | ( | ( | ||||
Net cash received on settlements of derivative instruments | ( | ( | ||||
Ending fair value of derivative instruments | $ | ( | $ | | ||
The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated:
March 31, | December 31, | |||||||
Classification | Balance Sheet Location | 2025 | 2024 | |||||
Assets: | ||||||||
Current assets | Derivative assets | $ | — | $ | | |||
Long-term assets | Derivative assets | — | | |||||
Liabilities: | ||||||||
Current liabilities | Derivative liabilities | ( | ( | |||||
Long-term liabilities | Derivative liabilities | ( | ( | |||||
$ | ( | $ | | |||||
As of March 31, 2025, 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 | ||||||||
April 2025 - December 2025 | | $ | | $ | | $ | | ||||
January 2026 - December 2026 | | $ | | $ | | $ | | ||||
January 2027 - March 2027 | | $ | | $ | | $ | | ||||
Natural Gas Price Swaps
Notional | Weighted Average | Range (per MMBtu) | |||||||||
Volumes (MMBtu) | Fixed Price (per MMBtu) | Low | High | ||||||||
April 2025 - December 2025 | | $ | | $ | | $ | | ||||
January 2026 - December 2026 | | $ | | $ | | $ | | ||||
January 2027 - March 2027 | | $ | | $ | | $ | | ||||
NOTE 6—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 unaudited interim consolidated balance sheets approximated fair value as of March 31, 2025 and December 31, 2024 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. |
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| ● | 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 three months ended March 31, 2025 and 2024.
The Partnership’s commodity derivative instruments 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 | Total | |||||||||||
March 31, 2025 | |||||||||||||||
Assets | |||||||||||||||
Commodity derivative contracts | $ | — | $ | | $ | — | $ | ( | $ | — | |||||
Liabilities | |||||||||||||||
Commodity derivative contracts | $ | — | $ | ( | $ | — | $ | | $ | ( | |||||
December 31, 2024 | |||||||||||||||
Assets | |||||||||||||||
Commodity derivative contracts | $ | — | $ | | $ | — | $ | ( | $ | | |||||
Liabilities | |||||||||||||||
Commodity derivative contracts | $ | — | $ | ( | $ | — | $ | | $ | ( | |||||
NOTE 7—OIL AND NATURAL GAS PROPERTIES
Oil and natural gas properties consist of the following:
| March 31, | December 31, | ||||
2025 | 2024 | |||||
Oil and natural gas properties | ||||||
Proved properties | $ | | $ | | ||
Unevaluated properties | | | ||||
Less: accumulated depreciation, depletion and impairment | ( | ( | ||||
Total oil and natural gas properties | $ | | $ | | ||
Costs not subject to depletion | ||||||
Incurred in 2025 | $ | | ||||
Incurred in 2024 | — | |||||
Incurred in 2023 | | |||||
Prior | — | |||||
Total costs not subject to depletion | $ | | ||||
The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at
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impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The Partnership assesses all unevaluated properties on a 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 developed 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.
The Partnership did
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Depletion expense for the three months ended March 31, 2025 and 2024 was $
NOTE 8—LEASES
The Partnership is the lessee on a lease of administrative office space used for its operations. On December 26, 2024, the Partnership modified its existing operating leases associated with its main office used for operations. The lease commenced in February 2025, expanding the current office space and extending the lease term to 2035, with the exclusive right and option to renew and extend the lease at the expiration of the primary term. The Partnership does not have any material lessor arrangements. Substantially all the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in February 2035. 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 unaudited interim consolidated balance sheets. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of March 31, 2025 is
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 leases was
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 unaudited interim consolidated statements of operations for the three months ended March 31, 2025 and 2024. The total operating lease expense recorded for the three months March 31, 2025 and 2024 was $
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Future minimum lease commitments as of March 31, 2025 were as follows:
Total | 2025 | 2026 | 2027 | 2028 | 2029 | Thereafter | |||||||||||||||
Operating leases | $ | | $ | | $ | | $ | | $ | | $ | | $ | | |||||||
Less: Imputed Interest |
| ( |
| ||||||||||||||||||
Total | $ | |
| ||||||||||||||||||
NOTE 9—LONG-TERM DEBT
On June 13, 2023, the Partnership entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $
On July 24, 2023, the Partnership entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amended the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $
On December 8, 2023, in connection with the November 1, 2023 redetermination, the Partnership entered into Amendment No. 2 (the “Second Amendment”) to the A&R Credit Agreement. The amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and elected from $
The secured revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (i) the Secured Overnight Financing Rate (as defined in the A&R Credit Agreement) plus an applicable margin that varies from
The secured revolving credit facility is guaranteed by certain of the Partnership’s material subsidiaries and is collateralized by substantially all assets, including the oil and natural gas properties of such subsidiaries, including mortgages on at least
Customary borrowing base reductions and mandatory prepayments are required under the A&R Credit Agreement in connection with certain sales of certain types of borrowing base properties, sales of equity interests in guarantor subsidiaries owning such properties, certain debt issuances or certain types of swap terminations. In addition, Cash Balance (as defined in the First Amendment) above $
The Partnership is required to pay a commitment fee of
The A&R Credit Agreement requires the Partnership to maintain as of the last day of each fiscal quarter: (i) a Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of not more than
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The A&R Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments and other customary covenants. These covenants are subject to a number of limitations and exceptions.
Additionally, the A&R Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Partnership does not comply with the financial and other covenants in the A&R Credit Agreement, the Lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the A&R Credit Agreement and any outstanding unfunded commitments may be terminated.
During the three months ended March 31 2025, the Partnership borrowed an additional $
As of March 31, 2025, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of
For additional information on our secured revolving credit facility, please read Note 17―Subsequent Events.
NOTE 10—PREFERRED UNITS
In September 2023, the Partnership completed the private placement of
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
Beginning with the earlier of (i) the second anniversary of the original issuance date and (ii) immediately prior to a liquidation of the Partnership, the Series A Purchasers may, at any time (but not more often than once per quarter), elect to convert all or any portion of their Series A preferred units into a number of common units determined by multiplying the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that (a) any conversion is for an amount of common units with an aggregate value of at least $
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At any time on or after the second anniversary of the original issuance date, the Partnership will have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $
The Series A preferred units are redeemable at the option of the Series A Purchasers after
For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (i) prior to the fifth anniversary of the original issuance date, a
The Series A preferred units are classified as mezzanine equity on the consolidated balance sheets due to certain redemption provisions being outside of the Partnership’s control. The Partnership has elected to accrete changes in the redemption value of the Series A preferred units over the period from the date of issuance to the earliest redemption date. The Series A preferred units were estimated to be redeemable at a price of $
The Series A preferred units had a carrying value of $
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 fifth anniversary of the original issuance date, board appointment rights beginning on the sixth anniversary of the original issuance date, and in the case of events of default with respect to the Series A preferred units, the right to appoint
The terms of the Series A preferred units contain covenants preventing the Partnership from taking certain actions without the approval of the holders of % of the outstanding Series A preferred units, voting separately as a class.
NOTE 11—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS
The Partnership has issued units representing limited partner interests. As of March 31, 2025, the Partnership had a total of
On January 9, 2025, the Partnership completed an underwritten public offering of
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The following table summarizes the changes in the number of the Partnership’s common units:
Common Units | ||
Balance at December 31, 2024 | | |
Units issued for equity offering | | |
Common units issued under the A&R LTIP (1) | | |
Restricted units repurchased for tax withholding | ( | |
Conversion of Class B units to common units | | |
Forfeiture of restricted units | ( | |
Balance at March 31, 2025 | |
| (1) | Includes restricted units granted to certain employees and directors under the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan on February 25, 2025. |
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 2025 | $ | | |||||||
Q1 2024 | $ | | |||||||
For each Class B unit issued,
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.
Change in Ownership of Consolidated Subsidiaries
The following table summarizes the changes in common unitholders' equity due to changes in ownership interest during the period:
Three Months Ended March 31, | ||||||
2025 | 2024 | |||||
Net income attributable to the Partnership | $ | | $ | | ||
Changes in ownership of consolidated subsidiaries, net | ( | | ||||
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest | $ | | $ | | ||
NOTE 12—EARNINGS PER COMMON UNIT
Basic earnings per common unit is calculated by dividing net income attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 13) for its employees and directors and potential conversion of Series A preferred units and Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Series A preferred units and 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 A&R 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 A&R LTIP are nonparticipating securities.
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The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings per common unit:
Three Months Ended March 31, | ||||||
2025 | 2024 | |||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | | $ | | ||
Distribution and accretion on Series A preferred units | | | ||||
Net income attributable to non-controlling interests in OpCo and distribution on Class B units | | | ||||
Diluted net income attributable to common units of Kimbell Royalty Partners, LP | $ | | $ | | ||
Weighted average number of common units outstanding: | ||||||
Basic | | | ||||
Effect of dilutive securities: | ||||||
Series A preferred units | | | ||||
Class B units | | | ||||
Restricted units | | | ||||
Diluted | | | ||||
Net income per unit attributable to common units of Kimbell Royalty Partners, LP | ||||||
Basic | $ | | $ | | ||
Diluted | $ | | $ | | ||
The calculation of diluted net income per share for the three months ended March 31, 2025 and 2024 includes the conversion of all Series A preferred units and Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method.
NOTE 13—UNIT-BASED COMPENSATION
On May 1, 2024, the Board of Directors approved and adopted the first amendment to the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as so amended, the “A&R LTIP”), which increased the number of common units available to be awarded under the A&R LTIP by
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 under the A&R LTIP to the Partnership’s employees and directors is determined by utilizing the market value of the Partnership’s common units on the respective grant date.
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The following table presents a summary of the Partnership’s unvested restricted units.
Weighted |
| Weighted | |||||
Average | Average | ||||||
Grant-Date | Remaining | ||||||
Fair Value | Contractual | ||||||
Units | per Unit | Term | |||||
Unvested at December 31, 2024 | | $ | |
| |||
Awarded | | | — | ||||
Vested | ( | | — | ||||
Forfeited | ( | | — | ||||
Unvested at March 31, 2025 (1) | | $ | |
| |||
| (1) | As of March 31, 2025, there was $ |
NOTE 14—INCOME TAXES
As discussed in Note 1, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. The non-controlling interest, which represents OpCo common unitholders’, are not subject to federal income taxes.
The Partnership records income taxes for interim periods based on an estimated annual effective tax rate. The estimated annual effective rate is recomputed on a quarterly basis and may fluctuate due to changes in forecasted annual operating income, positive or negative changes to the valuation allowance for net deferred tax assets, changes in forecasted annual income (loss) attributable to non-controlling interest and changes to actual or forecasted permanent book to tax differences. The Partnership’s effective tax rate for the three months ended March 31, 2025 was
NOTE 15—RELATED PARTY TRANSACTIONS
The Partnership currently has a management services agreement with Kimbell Operating, which has a separate services agreement with K3 Royalties, LLC (“K3 Royalties”). Pursuant to the K3 Royalties service agreement, K3 Royalties 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 may identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and K3 Royalties under their respective services agreements will reduce the amount of cash available for distribution on common units to the Partnership’s unitholders. During the three months ended March 31, 2025, the Partnership made payments to K3 Royalties in the amount of $
The Partnership received $
NOTE 16—COMMITMENTS AND CONTINGENCIES
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 March 31, 2025.
NOTE 17—SUBSEQUENT EVENTS
The Partnership has evaluated events that occurred subsequent to March 31, 2025 in the preparation of its unaudited interim consolidated financial statements.
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Long-Term Debt
On May 1, 2025, in connection with the recent redetermination, the Partnership entered into Amendment No. 3 (the “Third Amendment”) to the A&R Credit Agreement. The amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and elected from $
Drawdown on Secured Revolving Credit Facility
On May 1, 2025, the Partnership borrowed an additional $
Partial Redemption of Preferred Units
On May 7, 2025, the Partnership completed the redemption of
Distributions
On
The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited interim consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024 (the “2024 Form 10-K”).
Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “our Partnership,” “we” “our,” or “us” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to our subsidiary Kimbell Royalty Operating, LLC. References to “our General Partner” refer to Kimbell Royalty GP, LLC. References to “our Sponsors” refer to affiliates of our founders, 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 our Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to us.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements and information in this Quarterly Report may constitute forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
| ● | our ability to replace our reserves; |
| ● | our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions; |
| ● | our ability to execute our business strategies; |
| ● | the volatility of realized prices for oil, natural gas and natural gas liquids (“NGLs”), including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries; |
| ● | the level of production on our properties; |
| ● | the level of drilling and completion activity by the operators of our properties; |
| ● | our ability to forecast identified drilling locations, gross horizontal wells, drilling inventory and estimates of reserves on our properties and on properties we seek to acquire; |
| ● | regional supply and demand factors, delays or interruptions of production; |
| ● | industry, economic, business or political conditions, including the energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies; |
| ● | trade policies and tensions, including changes in, or the imposition of, tariffs and/or trade barriers and the economic impacts, volatility and uncertainty resulting therefrom, which may have varying effects on commodity prices; |
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| ● | the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine and the conflict in the Middle East; |
| ● | revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties; |
| ● | impact of impairment expense on our financial statements; |
| ● | competition in the oil and natural gas industry generally and the mineral and royalty industry in particular; |
| ● | the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations; |
| ● | title defects in the properties in which we acquire an interest; |
| ● | the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel to the operators of our properties; |
| ● | restrictions on or the availability of the use of water in the business of the operators of our properties; |
| ● | the availability of transportation facilities; |
| ● | the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals; |
| ● | federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry, including regulation, proposals, and executive orders focused on addressing climate change; |
| ● | future operating results; |
| ● | exploration and development drilling prospects, inventories, projects and programs; |
| ● | operating hazards faced by the operators of our properties; |
| ● | the ability of the operators of our properties to keep pace with technological advancements; |
| ● | uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions; and |
| ● | our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures. |
These factors are discussed in further detail in the 2024 Form 10-K under “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II and elsewhere in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.
Overview
We are 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. We have elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are 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. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.
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As of March 31, 2025, we owned mineral and royalty interests in approximately 12.3 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 55% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of March 31, 2025, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 131,000 gross wells, including over 52,000 wells in the Permian Basin.
The following table summarizes our ownership in United States basins and producing regions and information about the wells in which we have a mineral or royalty interest as March 31, 2025:
Average Daily | ||||||||
Production | ||||||||
Basin or Producing Region | Gross Acreage | Net Acreage | (Boe/d)(6:1)(1) | Well Count | ||||
Permian Basin | 3,404,777 | 27,799 | 10,831 | 52,162 | ||||
Mid‑Continent |
| 5,868,926 | 48,832 | 4,577 | 21,029 | |||
Terryville/Cotton Valley/Haynesville |
| 1,428,907 | 7,919 | 3,918 | 16,372 | |||
Appalachian Basin | 741,354 | 23,203 | 1,590 | 3,965 | ||||
Bakken/Williston Basin |
| 1,640,077 | 6,138 | 849 | 5,519 | |||
Eagle Ford |
| 624,148 | 6,730 | 1,774 | 4,448 | |||
DJ Basin/Rockies/Niobrara |
| 74,152 | 1,036 | 775 | 12,598 | |||
Other |
| 3,232,560 | 36,693 | 1,187 | 15,478 | |||
Total |
| 17,014,901 | 158,350 | 25,501 | 131,571 |
| (1) | “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our 2024 Form 10-K. |
The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of March 31, 2025:
Basin or Producing Region(1) | Gross DUCs | Gross Permits | Net DUCs | Net Permits | ||||
Permian Basin | 503 | 491 | 2.64 | 2.55 | ||||
Mid‑Continent |
| 114 | 78 | 0.91 | 0.41 | |||
Terryville/Cotton Valley/Haynesville |
| 40 | 22 | 0.37 | 0.16 | |||
Appalachian Basin | 2 | 1 | 0.02 | — | ||||
Bakken/Williston Basin |
| 70 | 67 | 0.31 | 0.22 | |||
Eagle Ford |
| 67 | 22 | 0.32 | 0.08 | |||
DJ Basin/Rockies/Niobrara |
| 12 | 1 | 0.10 | 0.01 | |||
Total |
| 808 | 682 | 4.67 | 3.43 |
| (1) | The above table represents DUCs and permitted locations only, and there is no guarantee that the DUCs or permitted locations will be developed into producing wells in the future. |
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Recent Developments
Equity Offering
On January 9, 2025, we completed an underwritten public offering of 11,500,000 common units for net proceeds of approximately $163.6 million (the “2025 Equity Offering”). We used the net proceeds from the 2025 Equity Offering to purchase OpCo common units. The Operating Company ultimately used the net proceeds of the 2025 Equity Offering to fund the Boren Acquisition (as defined below).
Acquisitions
On January 17, 2025, we completed the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in a transaction valued at approximately $230.4 million, including transaction costs and certain customary post-closing adjustments. We funded the cash consideration of the purchase price with borrowings under our secured revolving credit facility and net proceeds from the 2025 Equity Offering. The oil and gas properties acquired are located under the Mabee Ranch in the Midland Basin in Texas.
Quarterly Distributions
On May 8, 2025, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.47 per common unit representing limited partner interests in the Partnership (“common unit”) and common unit of the Operating Company (“OpCo common unit”) for the quarter ended March 31, 2025. We intend to pay the distributions on May 28, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on May 20, 2025.
We will pay a cash distribution on the Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”) of approximately $4.8 million for the quarter ended March 31, 2025. We intend to pay the distribution subsequent to May 8, 2025 and prior to the distribution on the common units and OpCo common units.
Business Environment
Global Conflicts and Uncertainties
In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. In January 2025, Israel and Hamas agreed to a ceasefire deal, however, in March 2025 Israel carried out air strikes against Hamas, suggesting there is no indication on the extent of the ceasefire. These conflicts and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us.
President Trump has executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of commodities, increase the price of supplies and raw materials that we rely on, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our operations and expenses.
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Commodity Prices and Demand
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from various OPEC announcements and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (the “EIA”).
Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | |||||||||||
High |
| Low | High |
| Low | |||||||
Oil ($/Bbl) | $ | 80.73 | $ | 66.31 | $ | 84.39 | $ | 70.62 | ||||
Natural gas ($/MMBtu) | $ | 9.86 | $ | 2.93 | $ | 13.20 | $ | 1.25 | ||||
On April 28, 2025, the West Texas Intermediate posted price for crude oil was $63.30 per Bbl and the Henry Hub spot market price of natural gas was $2.96 per MMBtu.
The following table, as reported by the EIA, sets forth the average daily prices for oil and natural gas.
Three Months Ended March 31, | |||||||
2025 |
| 2024 | |||||
Oil ($/Bbl) | $ | 71.78 | $ | 77.50 | |||
Natural gas ($/MMBtu) | $ | 4.14 | $ | 2.15 | |||
Rig Count
Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.
The Baker Hughes United States Rotary Rig count decreased by 4.3% to 575 active land rigs at March 31, 2025 compared to 601 active land rigs at March 31, 2024. The 575 active land rigs at March 31, 2025 increased slightly compared to 573 active land rigs at December 31, 2024. While the United States Rotary Rig count decreased year over year, overall production is not decreasing, indicating improved efficiencies are allowing sustained production from fewer rigs.
The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated:
March 31, | ||||
Basin or Producing Region | 2025 | 2024 | ||
Permian Basin | 49 | 50 | ||
Mid‑Continent | 19 | 23 | ||
Terryville/Cotton Valley/Haynesville | 6 | 9 | ||
Bakken/Williston Basin | 8 | 6 | ||
Eagle Ford | 5 | 8 | ||
DJ Basin/Rockies/Niobrara | 1 | 1 | ||
Other | 2 | 1 | ||
Total | 90 | 98 | ||
Sources of Our Revenue
Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices received.
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The following table presents the breakdown of our oil, natural gas and NGL revenues for the following periods:
Three Months Ended March 31, | ||||||
2025 |
| 2024 | ||||
Revenue | ||||||
Oil revenue | 58 | % | 70 | % | ||
Natural gas revenue | 29 | % | 17 | % | ||
NGL revenue | 13 | % | 13 | % | ||
100 | % | 100 | % | |||
We have entered into oil and natural gas commodity derivative agreements, which extend through March 2027, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests. For further discussion on our commodity derivative agreements, see “Note 5—Derivatives.”
Non-GAAP Financial Measures
Adjusted EBITDA and Cash Available for Distribution on Common Units
Adjusted EBITDA and cash available for distribution on common units are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution on common units are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.
We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non-cash unit based compensation and unrealized gains and losses on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
Adjusted EBITDA and cash available for distribution on common units should not be considered an alternative to net income (loss), oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA and cash available for distribution on common units may not be comparable to other similarly titled measures of other companies.
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The tables below present a reconciliation of Adjusted EBITDA and cash available for distribution on common units to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated (unaudited).
Three Months Ended March 31, | ||||||
2025 | 2024 | |||||
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: | ||||||
Net income | $ | 25,853,195 | $ | 9,336,939 | ||
Depreciation and depletion expense | 31,118,095 | 38,166,806 | ||||
Interest expense | 6,621,526 | 7,301,330 | ||||
Income tax expense | 1,089,426 | 922,568 | ||||
EBITDA | 64,682,242 | 55,727,643 | ||||
Impairment of oil and natural gas properties | — | 5,963,575 | ||||
Unit-based compensation | 3,861,815 | 3,684,080 | ||||
Loss on derivative instruments, net of settlements | 6,988,979 | 8,737,714 | ||||
Consolidated Adjusted EBITDA | 75,533,036 | 74,113,012 | ||||
Adjusted EBITDA attributable to non-controlling interest | (10,145,611) | (16,179,650) | ||||
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | 65,387,425 | 57,933,362 | ||||
Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ||||||
Cash interest expense | 4,051,203 | 5,234,705 | ||||
Cash distribution on Series A preferred units | 4,162,378 | 3,800,296 | ||||
Distribution on Class B units | 14,492 | 20,847 | ||||
Cash available for distribution on common units | $ | 57,159,352 | $ | 48,877,514 | ||
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Three Months Ended March 31, | ||||||
2025 | 2024 | |||||
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units: | ||||||
Net cash provided by operating activities | $ | 54,152,677 | $ | 69,045,616 | ||
Interest expense |
| 6,621,526 |
| 7,301,330 | ||
Income tax expense | 1,089,426 | 922,568 | ||||
Impairment of oil and natural gas properties |
| — |
| (5,963,575) | ||
Amortization of right-of-use assets | (85,055) |
| (86,324) | |||
Amortization of loan origination costs |
| (534,205) |
| (530,130) | ||
Unit-based compensation |
| (3,861,815) |
| (3,684,080) | ||
Forfeiture of restricted units | 56,807 |
| — | |||
Loss on derivative instruments, net of settlements |
| (6,988,979) |
| (8,737,714) | ||
Changes in operating assets and liabilities: | ||||||
Oil, natural gas and NGL receivables |
| 15,074,138 |
| (4,316,194) | ||
Accounts receivable and other current assets |
| (16,361) |
| 1,149,530 | ||
Accounts payable |
| 938,173 |
| (312,764) | ||
Other current liabilities |
| (1,825,602) |
| 847,611 | ||
Operating lease liabilities | 61,512 |
| 91,769 | |||
EBITDA | 64,682,242 | 55,727,643 | ||||
Add: | ||||||
Impairment of oil and natural gas properties |
| — |
| 5,963,575 | ||
Unit-based compensation |
| 3,861,815 |
| 3,684,080 | ||
Loss on derivative instruments, net of settlements |
| 6,988,979 |
| 8,737,714 | ||
Consolidated Adjusted EBITDA | 75,533,036 | 74,113,012 | ||||
Adjusted EBITDA attributable to non-controlling interest | (10,145,611) | (16,179,650) | ||||
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | 65,387,425 | 57,933,362 | ||||
Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ||||||
Cash interest expense | 4,051,203 | 5,234,705 | ||||
Cash distribution on Series A preferred units | 4,162,378 | 3,800,296 | ||||
Distribution on Class B units | 14,492 | 20,847 | ||||
Cash available for distribution on common units | $ | 57,159,352 | $ | 48,877,514 | ||
Factors Affecting the Comparability of Our Results to Our Historical Results
Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below.
Ongoing Acquisition Activities
Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three months ended March 31, 2025 and 2024 include the Boren Acquisition in January 2025.
Further, the affiliates of our Sponsors and Contributing Parties have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such parties offer them to us. We may decide to fund any acquisition, including any potential dropdowns, with cash, common units, other equity securities, proceeds from borrowings under our secured revolving credit facility or the issuance of debt securities, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.
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We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long-term results for some time thereafter.
Impairment of Oil and Natural Gas Properties
Accounting standards require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience significant downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.
We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 2025. As a result of our full cost ceiling analysis, we recorded an impairment on our oil and natural gas properties of $6.0 million during the three months ended March 31, 2024. The impairment was primarily attributed to the decline in the 12-month average price of oil and natural gas for the three months ended March 31, 2024. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas.
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Results of Operations
The table below summarizes our revenue and expenses and production data for the periods indicated (unaudited).
Three Months Ended March 31, | ||||||
2025 | 2024 | |||||
Operating Results: | ||||||
Revenue | ||||||
Oil, natural gas and NGL revenues | $ | 89,951,203 | $ | 87,499,509 | ||
Lease bonus and other income | 310,989 | 438,796 | ||||
Loss on commodity derivative instruments, net | (6,053,426) | (5,704,361) | ||||
Total revenues | 84,208,766 | 82,233,944 | ||||
Costs and expenses | ||||||
Production and ad valorem taxes |
| 5,375,429 |
| 6,531,901 | ||
Depreciation and depletion expense |
| 31,118,095 |
| 38,166,806 | ||
Impairment of oil and natural gas properties |
| — |
| 5,963,575 | ||
Marketing and other deductions |
| 4,501,767 |
| 4,562,944 | ||
General and administrative expense |
| 9,636,743 |
| 9,447,881 | ||
Total costs and expenses |
| 50,632,034 |
| 64,673,107 | ||
Operating income |
| 33,576,732 |
| 17,560,837 | ||
Other expense | ||||||
Interest expense |
| (6,621,526) |
| (7,301,330) | ||
Other expense |
| (12,585) |
| — | ||
Net income before income taxes | 26,942,621 | 10,259,507 | ||||
Income tax expense | 1,089,426 | 922,568 | ||||
Net income | 25,853,195 | 9,336,939 | ||||
Distribution and accretion on Series A preferred units | (5,202,862) | (5,256,287) | ||||
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests | (2,773,757) | (890,849) | ||||
Distribution on Class B units | (14,492) | (20,847) | ||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | 17,862,084 | $ | 3,168,956 | ||
Production Data: | ||||||
Oil (Bbls) |
| 749,744 |
| 804,589 | ||
Natural gas (Mcf) |
| 6,618,953 |
| 7,413,069 | ||
Natural gas liquids (Bbls) |
| 442,187 |
| 458,247 | ||
Combined volumes (Boe) (6:1) |
| 2,295,090 |
| 2,498,348 | ||
Comparison of the Three Months Ended March 31, 2025 to the Three Months Ended March 31, 2024
Oil, Natural Gas and NGL Revenues
For the three months ended March 31, 2025, our oil, natural gas and NGL revenues were $90.0 million, an increase of $2.5 million from $87.5 million for the three months ended March 31, 2024. The increase in oil, natural gas and NGL revenues was primarily related to an increase in the average prices received for natural gas and NGLs for the three months ended March 31, 2025 as discussed below.
Our revenues are a function of oil, natural gas and NGL production volumes sold and average prices received for those volumes. The production volumes were 2,295,090 Boe or 25,501 Boe/d, for the three months ended March 31, 2025, a decrease of 203,258 Boe or 1,953 Boe/d, from 2,498,348 Boe or 27,454 Boe/d, for the three months ended March 31, 2024. The decrease in production for the three months ended March 31, 2025 was primarily attributable to 252,653 Boe or 2,776 Boe/d of prior period production recognized for the three months ended March 31, 2024, partially offset by production associated with the Boren Acquisition.
Our operators received an average of $69.27 per Bbl of oil, $3.87 per Mcf of natural gas and $27.99 per Bbl of NGL for the volumes sold during the three months ended March 31, 2025 compared to $76.60 per Bbl of oil, $1.96 per Mcf of natural gas and $24.70 per Bbl of NGL for the volumes sold during the three months ended March 31, 2024. These average prices received during the three months ended March 31, 2025 decreased 9.6% or $7.33 per Bbl of oil and increased 97.4% or $1.91 per Mcf of natural gas as compared to the three months ended March 31, 2024. This change is
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consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 7.4% or $5.72 per Bbl of oil and an increase of 92.6% or $1.99 per Mcf of natural gas for the comparable periods.
Lease Bonus and Other Income
Lease bonus and other income for the three months ended March 31, 2025 remained relatively flat at $0.3 million, compared to $0.4 million for the three months ended March 31, 2024.
Loss on Commodity Derivative Instruments
Loss on commodity derivative instruments for the three months ended March 31, 2025 included $7.0 million of mark-to-market losses and $0.9 million of gains on the settlement of commodity derivative instruments compared to $8.7 million of mark-to-market losses and $3.0 million of gains on the settlement of commodity derivative instruments for the three months ended March 31, 2024. We recorded a mark-to-market losses for the three months ended March 31, 2025 and 2024 as a result of an increase in strip pricing from the previous quarter, partially offset by gains on the settlement of commodity derivative instruments.
Production and Ad Valorem Taxes
Production and ad valorem taxes for the three months ended March 31, 2025 were $5.4 million, a decrease of $1.1 million from $6.5 million for the three months ended March 31, 2024. The decrease in production and ad valorem taxes was primarily attributable to the decrease in oil and natural gas production, partially offset by an increase in production and ad valorem taxes associated with the Boren Acquisition.
Depreciation and Depletion Expense
Depreciation and depletion expense for the three months ended March 31, 2025 was $31.1 million, a decrease of $7.1 million from $38.2 million for the three months ended March 31, 2024. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $13.52 for the three months ended March 31, 2025, a decrease of $1.72 per barrel from the $15.24 average depletion rate per barrel for the three months ended March 31, 2024. The decrease in the depletion rate was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.
Impairment
We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 2025. We recorded an impairment on our oil and natural gas properties of $6.0 million during the three months ended March 31, 2024, as a result of our full cost ceiling analysis. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas.
Marketing and Other Deductions
Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended March 31, 2025 remained relatively flat at $4.5 million, compared to $4.6 million for the three months ended March 31, 2024.
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General and Administrative Expenses
General and administrative expenses for the three months ended March 31, 2025 were $9.6 million, an increase of $0.2 million compared to $9.4 million for the three months ended March 31, 2024. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to an increase in unit-based compensation expense.
Interest Expense
Interest expense for the three months ended March 31, 2025 was $6.6 million, compared to $7.3 million for the three months ended March 31, 2024. The decrease in interest expense was primarily due to a 1.03% decrease in the weighted average interest rate on our outstanding borrowings for the three months ended March 31, 2025.
Income Tax Expense
We recorded an income tax expense of $1.1 million and $0.9 million for the three months ended March 31, 2025 and 2024, respectively.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. On June 13, 2023, we entered into the A&R Credit Agreement (as defined below). On July 24, 2023, we entered into the First Amendment (as defined below) to the A&R Credit Agreement that, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit us to issue certain preferred equity interests. On December 8, 2023, we entered into the Second Amendment (as defined below) to the A&R Credit Agreement that, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million. See “Indebtedness” below for further discussion of our secured revolving credit facility.
Cash Distribution Policy
The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in our partnership agreement and in the limited liability company agreement of the Operating Company. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the first quarter of 2025 for the repayment of $16.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the first quarter of 2025. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future.
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We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.
It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we completed the Boren Acquisition partially with net proceeds from the 2025 Equity Offering. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our first quarter 2025 distributions.
Cash Flows
The table below presents our cash flows for the periods indicated.
Three Months Ended March 31, | ||||||
2025 |
| 2024 | ||||
Cash Flow Data: | ||||||
Net cash provided by operating activities | $ | 54,152,677 | $ | 69,045,616 | ||
Net cash used in investing activities |
| (222,949,985) |
| (91,368) | ||
Net cash provided by (used in) financing activities |
| 170,256,669 |
| (60,267,298) | ||
Net increase in cash and cash equivalents | $ | 1,459,361 | $ | 8,686,950 | ||
Operating Activities
Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the three months ended March 31, 2025 were $54.2 million, a decrease of $14.8 million compared to $69.0 million for the three months ended March 31, 2024.
Investing Activities
Cash flows used in investing activities for the three months ended March 31, 2025 were $222.9 million compared to $0.1 million for the three months ended March 31, 2024. For the three months ended March 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition. For the three months ended March 31, 2024, cash flows used in investing activities included costs associated with an acquisition and the purchase of equipment.
Financing Activities
Cash flows provided by financing activities were $170.3 million for the three months ended March 31, 2025 compared to $60.3 million of cash flows used in financing activities for the three months ended March 31, 2024. Cash flows provided by financing activities for the three months ended March 31, 2025 consists primarily of $163.6 million in proceeds from the 2025 Equity Offering and $74.1 million of additional borrowings under our secured revolving credit facility, partially offset by $48.1 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $14.3 million used to repay borrowings under our secured revolving credit facility and $5.1 million of restricted units repurchased for tax withholding.
Cash flows used in financing activities for the three months ended March 31, 2024 consists primarily of $46.5 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $13.8 million used to repay borrowings under our secured revolving credit facility and $4.9 million of restricted units repurchased for tax withholding, partially offset by $5.0 million of additional borrowings under our secured revolving credit facility.
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Indebtedness
On June 13, 2023, we entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated our existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million, with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.
On July 24, 2023, we entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The First Amendment amends the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million and (ii) permit us to issue certain preferred equity interests.
On December 8, 2023, we entered into Amendment No. 2 (the “Second Amendment”) to the A&R Credit Agreement. The Second Amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million.
For additional information on our secured revolving credit facility, please read Note 9―Long-Term Debt and Note 17―Subsequent Events to the unaudited interim consolidated financial statements included in this Quarterly Report.
Tax Matters
Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. The non-controlling interest, which represents OpCo common unitholders’, are not subject to federal income taxes. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2024. Our estimates regarding treatment of our distributions are based on currently available information only and are subject to change, including with respect to prior quarters.
Distributions in excess of the amount taxable as dividend income will reduce a common unitholder’s tax basis in its common units or produce capital gain to the extent they exceed a common unitholder’s tax basis. Any reduced tax basis will increase a common unitholder’s capital gain when it sells its common units. Our estimates are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax “earnings and profits.” Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter.
New and Revised Financial Accounting Standards
The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies to our unaudited interim consolidated financial statements included elsewhere in this Quarterly Report.
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Critical Accounting Policies and Related Estimates
There have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our 2024 Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
There have been no significant changes to our contractual obligations previously disclosed in our 2024 Form 10-K. As of March 31, 2025, we did not have any off-balance sheet arrangements. See Note 8—Leases to the unaudited interim consolidated financial statements for additional information regarding our operating leases.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect commodity prices to be even more volatile in the future as a result of ongoing international supply and demand imbalances and limited international storage capacity. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties.
Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.
Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our 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.
Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 5—Derivatives to the unaudited interim consolidated financial statements in Item 1 of this Quarterly Report for additional information regarding our commodity derivatives.
Counterparty and Customer Credit Risk
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2025, we had seven counterparties to our derivative contracts, which are also lenders under our secured revolving credit facility.
As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.
Interest Rate Risk
We will have exposure to changes in interest rates on our indebtedness. As of March 31, 2025, we had total borrowings outstanding under our secured revolving credit facility of $299.0 million. The impact of a 1% increase in the
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interest rate on this amount of debt could result in an increase in interest expense of approximately $3.0 million annually, assuming that our indebtedness remained constant throughout the year.
Inflation
Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2024 through March 31, 2025. However, inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the management of our General Partner, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Disclosure controls and procedures are defined as controls designed to ensure that the information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2025.
Changes in Internal Control over Financial Reporting
There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II – OTHER INFORMATION
Item 1. Legal Proceedings
For a description of the Partnership’s legal proceedings, see Note 16—Commitments and Contingencies to the unaudited interim consolidated financial statements included in Part I of this Quarterly Report and incorporated by reference herein.
Item 1A. Risk Factors
In addition to the risks and uncertainties discussed in this Quarterly Report, included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks set out under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2024 Form 10-K. The following supplements and updates the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024. These risk factors could materially affect our business, financial condition and results of operations. The volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, these risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.
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Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.
Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. Several recent tariff announcements by the U.S. federal government have been followed by announcements of limited exemptions and temporary pauses. These actions are unprecedented, have caused substantial uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods and commodities.
Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and increased volatility in commodity prices. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.
Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes, tariffs, trade agreements or policies, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.
Item 2. Unregistered Sales of Equity Securities
On February 12, 2025, we issued 3,162 common units to an existing OpCo unitholder in exchange for 3,162 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018, by and among us, the General Partner, the Operating Company and the other holders of OpCo common units and Class B units from time to time party thereto (the “Exchange Agreement”).
On February 14, 2025, we issued 29,418 common units to another existing OpCo unitholder in exchange for 29,418 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.
The issuance of each of the foregoing securities was exempt from the registration requirements of the Securities Act in reliance upon Section 4(a)(2) of the Securities Act.
Period | Total Number of Common Units Purchased(1) | Average Price Paid per Common Unit | Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs(2) | Maximum Number of Common Units That May Yet be Purchased Under the Plans or Programs(2) | |||||
January 1, 2025 - January 31, 2025 | — | $ | — | — | — | ||||
February 1, 2025 - February 29, 2025 | — | $ | — | — | — | ||||
March 1, 2025 - March 31, 2025 | 315,276 | $ | 14.99 | — | — | ||||
| (1) | All of the common units shown above were withheld during the three months ended March 31, 2025 to satisfy tax-withholding obligations arising in conjunction with the vesting of restricted units. The required withholding is calculated using the closing sales price per common unit reported by the New York Stock Exchange on the date prior to the applicable vesting date. |
| (2) | We did not have at any time during the quarter ended March 31, 2025, and currently do not have, a common unit repurchase program in place. |
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Item 5. Other Information
Rule 10b5-1 Plans
During the period covered by this report, none of the Partnership’s directors or executive officers have
Item 6. Exhibits
Exhibit |
| Description |
3.1 | — | |
3.2 | — | |
3.3 | — | |
3.4 | — | |
10.1+ | — | |
10.2 | ||
31.1* | — | |
31.2* | — | |
32.1** | — | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 |
32.2** | — | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 |
101.INS* | — | Inline XBRL Instance Document —the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
101.SCH* | — | Inline XBRL Taxonomy Extension Schema Document |
101.CAL* | — | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF* | — | Inline XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB* | — | Inline XBRL Taxonomy Extension Label Linkbase Document |
101.PRE* | — | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
104* | — | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
* | —filed herewith |
** | —furnished herewith |
+ | —Management contract or compensatory plan or arrangement. |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Kimbell Royalty Partners, LP | |||
By: | Kimbell Royalty GP, LLC | |||
its general partner | ||||
Date: May 8, 2025 | By: | /s/ Robert D. Ravnaas | ||
Name: | Robert D. Ravnaas | |||
Title: | Chief Executive Officer and Chairman | |||
Principal Executive Officer | ||||
Date: May 8, 2025 |
| By: | /s/ R. Davis Ravnaas | |
Name: | R. Davis Ravnaas | |||
Title: | President and Chief Financial Officer | |||
Principal Financial Officer | ||||
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