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 July 26, 2024, 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)
June 30, | December 31, | |||||
2024 | 2023 | |||||
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 (deficit) 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.
1
KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
2024 | 2023 | 2024 | 2023 | |||||||||
Revenue | ||||||||||||
Oil, natural gas and NGL revenues | $ | | $ | | $ | | $ | | ||||
Lease bonus and other income | | | | | ||||||||
(Loss) gain 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 | | | | | ||||||||
Consolidated variable interest entities related: | ||||||||||||
General and administrative expense | — | | — | | ||||||||
Total costs and expenses | | | | | ||||||||
Operating income | | | | | ||||||||
Other (expense) income | ||||||||||||
Interest expense | ( | ( | ( | ( | ||||||||
Loss on extinguishment of debt | — | ( | — | ( | ||||||||
Other expense | — | ( | — | ( | ||||||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | — | | — | | ||||||||
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.
2
KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY
(Unaudited)
Six Months Ended June 30, 2024 | ||||||||||||||||||
Non-controlling | ||||||||||||||||||
| Common Units |
| Amount |
| Class B Units |
| Amount | Interest (Deficit) | 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 | — | ( | — | — | — | ( | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at March 31, 2024 | | | | | | | ||||||||||||
Conversion of Class B units to common units | | | ( | ( | ( | ( | ||||||||||||
Unit-based compensation | — | | — | — | — | | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution and accretion on Series A preferred units | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at June 30, 2024 | | $ | | | $ | | $ | ( | $ | | ||||||||
3
KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY — (Continued)
(Unaudited)
Six Months Ended June 30, 2023 | ||||||||||||||||||
Non-controlling | ||||||||||||||||||
| Common Units |
| Amount |
| Class B Units |
| Amount | (Deficit) Interest | Total | |||||||||
Balance at January 1, 2023 | | $ | | | $ | | $ | ( | $ | | ||||||||
Restricted units repurchased for tax withholding | ( | ( | — | — | — | ( | ||||||||||||
Unit-based compensation | | | — | — | — | | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at March 31, 2023 | | | | | ( | | ||||||||||||
Units issued for acquisition | | | | | | | ||||||||||||
Unit-based compensation | — | | — | — | — | | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions | — | | — | — | | | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at June 30, 2023 | | $ | | | $ | | $ | | $ | | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
4
KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30, | ||||||
2024 |
| 2023 | ||||
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 | | | ||||
Loss on extinguishment of debt | — | | ||||
Unit-based compensation | | | ||||
Loss (gain) 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 | ( | ( | ||||
Consolidated variable interest entities related: | ||||||
Interest earned on marketable securities in trust account | — | ( | ||||
Other assets and liabilities | — | ( | ||||
Net cash provided by operating activities | | | ||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||
Purchases of property and equipment | ( | ( | ||||
Purchase of oil and natural gas properties | ( | ( | ||||
Proceeds from trust of variable interest entity | — | | ||||
Consolidated variable interest entities related: | ||||||
Cash paid for transaction costs | — | | ||||
Cash received from investments held in trust | — | | ||||
Net cash (used in) provided by investing activities | ( | | ||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||
Contributions from Class B unitholders | — | | ||||
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 | ( | ( | ||||
Consolidated variable interest entities related: | ||||||
Redemption of Kimbell Tiger Acquisition Corporation equity units | — | ( | ||||
Net cash used in financing activities | ( | ( | ||||
NET DECREASE IN CASH AND CASH EQUIVALENTS | ( | ( | ||||
CASH AND CASH EQUIVALENTS, beginning of period | | | ||||
CASH AND CASH EQUIVALENTS, end of period | $ | | $ | | ||
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
(Unaudited)
Six Months Ended June 30, | ||||||
2024 |
| 2023 | ||||
Supplemental cash flow information: | ||||||
Cash paid for interest | $ | | $ | | ||
Non-cash investing and financing activities: | ||||||
Units issued in exchange for oil and natural gas properties | $ | — | $ | | ||
Noncash deemed distribution to Series A preferred units | $ | | $ | — | ||
Distribution on Series A preferred units in accounts payable | $ | | $ | — | ||
Recognition of tenant improvement asset | $ | | $ | | ||
Consolidated variable interest entities related: | ||||||
Reduction of deferred underwriting commission associated with redemption of Kimbell Tiger Acquisition Corporation equity units | $ | — | $ | ( | ||
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, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership.
NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION
Organization
Kimbell Royalty Partners, LP is a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. 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, 2023 (the “2023 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 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 in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.
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Global Conflicts
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. 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.
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 2023 Form 10-K, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the three and six months ended June 30, 2024.
Consolidation
The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required.
In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.
For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.
VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.
Investments Held in Trust by Consolidated Variable Interest Entities
Investments held in trust represented funds raised by Kimbell Tiger Acquisition Corporation (“TGR”), a consolidated special purpose acquisition company, through TGR’s initial public offering. These funds were held in an
8
actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and were presented on the balance sheet at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in other income (expense)—interest earned on marketable securities in trust account on the accompanying unaudited interim consolidated statements of operations. Interest earned on marketable securities in trust account was $
Recently Issued Accounting Pronouncements
In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 820): Improvements to Reportable Segment Disclosures.” The amendments in this update apply to all public entities that are required to report segment information in accordance with Topic 280, Segment Reporting. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is 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 December 2023, the FASB issued 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. 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 June 30, | Six Months Ended June 30, | |||||||||||
2024 |
| 2023 | 2024 |
| 2023 | |||||||
Oil revenue | $ | | $ | | $ | | $ | | ||||
Natural gas revenue | | | | | ||||||||
NGL revenue | | | | | ||||||||
Total Oil, natural gas and NGL revenues | $ | | $ | | $ | | $ | | ||||
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NOTE 4—ACQUISITIONS AND SPECIAL PURPOSE ACQUISITION COMPANY
Acquisitions
On September 13, 2023, the Partnership completed the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in a cash transaction valued at approximately $
On May 17, 2023, the Partnership completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”). The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $
Special Purpose Acquisition Company
On February 8, 2022, the Partnership’s previously dissolved special purpose acquisition company and subsidiary, TGR, consummated its $
On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock of TGR, par value $
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 June 30, 2024, 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 for the first nearby month futures contract corresponding to the relevant contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the
10
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 June 30, | Six Months Ended June 30, | |||||||||||
2024 | 2023 | 2024 | 2023 | |||||||||
Beginning fair value of derivative instruments | $ | | $ | | $ | | $ | ( | ||||
(Loss) gain on commodity derivative instruments, net | ( | | ( | | ||||||||
Net cash (received) paid 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:
June 30, | December 31, | |||||||
Classification | Balance Sheet Location | 2024 | 2023 | |||||
Assets: | ||||||||
Current assets | Derivative assets | $ | | $ | | |||
Long-term assets | Derivative assets | | | |||||
Liabilities: | ||||||||
Current liabilities | Derivative liabilities | ( | ( | |||||
Long-term liabilities | Derivative liabilities | ( | ( | |||||
$ | | $ | | |||||
As of June 30, 2024, 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 | ||||||||
July 2024 - December 2024 | | $ | | $ | | $ | | ||||
January 2025 - December 2025 | | $ | | $ | | $ | | ||||
January 2026 - June 2026 | | $ | | $ | | $ | | ||||
Natural Gas Price Swaps
Notional | Weighted Average | Range (per MMBtu) | |||||||||
Volumes (MMBtu) | Fixed Price (per MMBtu) | Low | High | ||||||||
July 2024 - December 2024 | | $ | | $ | | $ | | ||||
January 2025 - December 2025 | | $ | | $ | | $ | | ||||
January 2026 - June 2026 | | $ | | $ | | $ | | ||||
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 June 30, 2024 and December 31, 2023 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 and six months ended June 30, 2024 and 2023.
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 | |||||||||||
June 30, 2024 | |||||||||||||||
Assets | |||||||||||||||
Commodity derivative contracts | $ | — | $ | | $ | — | $ | — | $ | | |||||
Liabilities | |||||||||||||||
Commodity derivative contracts | $ | — | $ | ( | $ | — | $ | — | $ | ( | |||||
December 31, 2023 | |||||||||||||||
Assets | |||||||||||||||
Commodity derivative contracts | $ | — | $ | | $ | — | $ | — | $ | | |||||
Liabilities | |||||||||||||||
Commodity derivative contracts | $ | — | $ | ( | $ | — | $ | — | $ | ( | |||||
NOTE 7—OIL AND NATURAL GAS PROPERTIES
Oil and natural gas properties consist of the following:
| June 30, | December 31, | ||||
2024 | 2023 | |||||
Oil and natural gas properties | ||||||
Proved properties | $ | | $ | | ||
Unevaluated properties | | | ||||
Less: accumulated depreciation, depletion and impairment | ( | ( | ||||
Total oil and natural gas 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
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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.
As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $
NOTE 8—LEASES
Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. Currently, the only substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations.
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 June 30, 2024 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 and six months ended June 30, 2024 and 2023. The total operating lease expense recorded for both the three months June 30, 2024 and 2023 was $
Future minimum lease commitments as of June 30, 2024 were as follows:
Total | 2024 | 2025 | 2026 | 2027 | 2028 | 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 $
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off all unamortized loan origination costs associated with the lenders to the Partnership’s existing credit agreement that did not participate in the A&R Credit Agreement.
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 aggregate elected commitments 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 to 1.0 and (ii) a ratio of current assets to current liabilities of not less than to 1.0.
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 six months ended June 30, 2024, the Partnership borrowed an additional $
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As of June 30, 2024, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of
NOTE 10—PREFERRED UNITS
On August 2, 2023, the Partnership entered into a Series A preferred unit purchase agreement with certain funds managed by affiliates of Apollo (NYSE: APO) (collectively, the “Series A Purchasers”) to issue and sell up to
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 $
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
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Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (b) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to
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
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 June 30, 2024, the Partnership had a total of
On August 7, 2023, the Partnership completed an underwritten public offering of
The following table summarizes the changes in the number of the Partnership’s common units:
Common Units | ||
Balance at December 31, 2023 | | |
Common units issued under the A&R LTIP (1) | | |
Restricted units repurchased for tax withholding | ( | |
Conversion of Class B units to common units | | |
Balance at June 30, 2024 | |
| (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 19, 2024. |
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 2024 | $ | | |||||||
Q2 2024 | $ | | |||||||
Q1 2023 | $ | | |||||||
Q2 2023 | $ | | |||||||
For each Class B unit issued,
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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.
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.
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 June 30, | Six Months Ended June 30, | |||||||||||
2024 | 2023 | 2024 | 2023 | |||||||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | | $ | | $ | | $ | | ||||
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions | — | | — | | ||||||||
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions | | | | | ||||||||
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 and six months ended June 30, 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. The calculation of diluted net income per
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share for the three and six months ended June 30, 2023 includes the conversion of all 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.
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, 2023 | | $ | |
| |||
Awarded | | | — | ||||
Vested | ( | | — | ||||
Unvested at June 30, 2024 (1) | | $ | |
| |||
| (1) | As of June 30, 2024, 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 June 30, 2024 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
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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. The Partnership previously had a services agreement with BJF Royalties, LLC (“BJF Royalties”), which was terminated upon the death of Ben Fortson on May 19, 2024.
During the three and six months ended June 30, 2024,
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 June 30, 2024.
NOTE 17—SUBSEQUENT EVENTS
The Partnership has evaluated events that occurred subsequent to June 30, 2024 in the preparation of its unaudited interim consolidated financial statements.
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, 2023 (the “2023 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, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of 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 outcome of the U.S. presidential election and the energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies; |
| ● | 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; |
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| ● | 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 the Biden administration’s proposals and recent 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 2023 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.
As of June 30, 2024, we owned mineral and royalty interests in approximately 12.2 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres
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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 June 30, 2024, 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 129,000 gross wells, including over 50,000 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 June 30, 2024:
Average Daily | ||||||||
Production | ||||||||
Basin or Producing Region | Gross Acreage | Net Acreage | (Boe/d)(6:1)(1) | Well Count | ||||
Permian Basin | 3,336,729 | 26,928 | 9,211 | 50,604 | ||||
Mid‑Continent |
| 5,868,926 | 48,832 | 4,318 | 20,898 | |||
Terryville/Cotton Valley/Haynesville |
| 1,428,907 | 7,919 | 4,387 | 16,297 | |||
Appalachian Basin | 741,354 | 23,203 | 1,708 | 3,929 | ||||
Bakken/Williston Basin |
| 1,640,077 | 6,138 | 931 | 5,358 | |||
Eagle Ford |
| 624,148 | 6,730 | 1,574 | 4,277 | |||
DJ Basin/Rockies/Niobrara |
| 74,152 | 1,036 | 836 | 12,556 | |||
Other |
| 3,232,560 | 36,693 | 1,145 | 15,444 | |||
Total |
| 16,946,853 | 157,479 | 24,110 | 129,363 |
| (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 2023 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 June 30, 2024:
Basin or Producing Region(1) | Gross DUCs | Gross Permits | Net DUCs | Net Permits | ||||
Permian Basin | 417 | 416 | 1.93 | 2.44 | ||||
Mid‑Continent |
| 130 | 64 | 0.89 | 0.70 | |||
Terryville/Cotton Valley/Haynesville |
| 53 | 20 | 0.33 | 0.38 | |||
Appalachian Basin | 5 | 3 | 0.01 | 0.01 | ||||
Bakken/Williston Basin |
| 55 | 102 | 0.10 | 0.23 | |||
Eagle Ford |
| 98 | 58 | 0.50 | 0.34 | |||
DJ Basin/Rockies/Niobrara |
| 4 | 9 | 0.06 | 0.04 | |||
Total |
| 762 | 672 | 3.82 | 4.14 |
| (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. |
Recent Developments
Quarterly Distributions
On August 1, 2024, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.42 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 June 30, 2024. We intend to pay the distributions on August 19, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on August 12, 2024.
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 $4.8 million for the quarter ended June 30, 2024. We intend to pay the distribution subsequent to August 1, 2024 and prior to the distribution on the common units and OpCo common units.
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Business Environment
Global Conflicts
In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas and is still active. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. These conflicts and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us.
Commodity Prices and Demand
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from various OPEC announcements and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (the “EIA”).
Six Months Ended June 30, 2024 | Six Months Ended June 30, 2023 | |||||||||||
High |
| Low | High |
| Low | |||||||
Oil ($/Bbl) | $ | 87.69 | $ | 70.62 | $ | 83.26 | $ | 66.61 | ||||
Natural gas ($/MMBtu) | $ | 13.20 | $ | 1.25 | $ | 3.78 | $ | 1.74 | ||||
On July 22, 2024, the West Texas Intermediate posted price for crude oil was $81.25 per Bbl and the Henry Hub spot market price of natural gas was $2.19 per MMBtu.
The following table, as reported by the EIA, sets forth the average daily prices for oil and natural gas.
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2024 |
| 2023 | 2024 |
| 2023 | ||||||||
Oil ($/Bbl) | $ | 81.81 | $ | 73.54 | $ | 79.69 | $ | 74.73 | |||||
Natural gas ($/MMBtu) | $ | 2.07 | $ | 2.16 | $ | 2.11 | $ | 2.40 | |||||
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 14.2% to 560 active land rigs at June 30, 2024 compared to 653 active land rigs at June 30, 2023. The 560 active land rigs at June 30, 2024 decreased by 6.8% compared to 601 active land rigs at March 31, 2024. While the average daily prices for oil and natural gas at June 30, 2024 remained relatively flat when compared to June 30, 2023, higher labor and equipment costs, as a result of inflation, discourages any substantial uptake in the market.
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The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated:
June 30, | ||||
Basin or Producing Region | 2024 | 2023 | ||
Permian Basin | 47 | 50 | ||
Mid‑Continent | 20 | 12 | ||
Terryville/Cotton Valley/Haynesville | 9 | 17 | ||
Appalachian Basin | 1 | — | ||
Bakken/Williston Basin | 7 | 4 | ||
Eagle Ford | 6 | 5 | ||
DJ Basin/Rockies/Niobrara | 1 | 1 | ||
Other | — | 1 | ||
Total | 91 | 90 | ||
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.
The following table presents the breakdown of our oil, natural gas and NGL revenues for the following periods:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
2024 |
| 2023 | 2024 |
| 2023 | |||||||
Revenue | ||||||||||||
Oil revenue | 70 | % | 70 | % | 70 | % | 64 | % | ||||
Natural gas revenue | 18 | % | 20 | % | 17 | % | 27 | % | ||||
NGL revenue | 12 | % | 10 | % | 13 | % | 9 | % | ||||
100 | % | 100 | % | 100 | % | 100 | % | |||||
We have entered into oil and natural gas commodity derivative agreements, which extend through June 2026, 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.
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, loss on extinguishment of debt, unrealized gains and losses on derivative instruments and operational impacts of VIEs, which include general and administrative expense and interest income. 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
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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.
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 June 30, | Six Months Ended June 30, | |||||||||||
2024 | 2023 | 2024 | 2023 | |||||||||
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: | ||||||||||||
Net income | $ | 15,186,529 | $ | 17,797,031 | $ | 24,523,468 | $ | 46,696,569 | ||||
Depreciation and depletion expense | 33,023,934 |
| 19,656,855 | 71,190,740 | 37,220,503 | |||||||
Interest expense | 6,946,580 |
| 6,341,118 | 14,247,910 | 11,804,522 | |||||||
Income tax expense | 1,759,282 | 909,057 | 2,681,850 | 2,312,040 | ||||||||
EBITDA | 56,916,325 |
| 44,704,061 | 112,643,968 | 98,033,634 | |||||||
Impairment of oil and natural gas properties | — |
| — | 5,963,575 | — | |||||||
Unit-based compensation | 5,108,318 |
| 3,289,740 | 8,792,398 | 6,459,740 | |||||||
Loss on extinguishment of debt | — |
| 480,244 | — | 480,244 | |||||||
Loss (gain) on derivative instruments, net of settlements | 3,796,313 | (2,600,713) | 12,534,027 | (15,100,314) | ||||||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | — | (1,069,854) | — | (3,508,691) | ||||||||
General and administrative expense | — | 219,473 | — | 927,699 | ||||||||
Consolidated Adjusted EBITDA | 65,820,956 | 45,022,951 | 139,933,968 | 87,292,312 | ||||||||
Adjusted EBITDA attributable to non-controlling interest | (10,011,035) | (10,871,674) | (26,190,685) | (19,008,901) | ||||||||
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | 55,809,921 | 34,151,277 | 113,743,283 | 68,283,411 | ||||||||
Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ||||||||||||
Cash interest expense | 5,620,423 | 4,442,318 | 10,855,128 | 8,566,027 | ||||||||
Cash distribution on Series A preferred units | 4,110,950 | — | 7,911,246 | — | ||||||||
Cash income tax refund | — | — | — | (639,325) | ||||||||
Distribution on Class B units | 20,847 | 31,601 | 41,694 | 47,085 | ||||||||
Cash available for distribution on common units | $ | 46,057,701 | $ | 29,677,358 | $ | 94,935,215 | $ | 60,309,624 | ||||
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Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
2024 | 2023 | 2024 | 2023 | |||||||||
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 | $ | 62,882,573 | $ | 31,518,529 | $ | 131,928,189 | $ | 78,572,135 | ||||
Interest expense |
| 6,946,580 |
| 6,341,118 |
| 14,247,910 |
| 11,804,522 | ||||
Income tax expense | 1,759,282 | 909,057 | 2,681,850 | 2,312,040 | ||||||||
Impairment of oil and natural gas properties |
| — |
| — |
| (5,963,575) |
| — | ||||
Amortization of right-of-use assets | (86,555) | (84,501) | (172,879) |
| (167,658) | |||||||
Amortization of loan origination costs |
| (530,130) |
| (492,732) |
| (1,060,260) |
| (1,008,830) | ||||
Loss on extinguishment of debt | — | (480,244) | — | (480,244) | ||||||||
Unit-based compensation |
| (5,108,318) |
| (3,289,740) |
| (8,792,398) |
| (6,459,740) | ||||
(Loss) gain on derivative instruments, net of settlements | (3,796,313) |
| 2,600,713 |
| (12,534,027) |
| 15,100,314 | |||||
Changes in operating assets and liabilities: | ||||||||||||
Oil, natural gas and NGL receivables |
| (1,486,074) |
| 9,070,691 |
| (5,802,268) |
| (1,987,323) | ||||
Accounts receivable and other current assets |
| (459,887) |
| 86,707 |
| 689,643 |
| (427,105) | ||||
Accounts payable |
| 352,173 |
| (450,078) |
| 39,409 |
| (159,557) | ||||
Other current liabilities |
| (3,651,026) |
| (3,175,769) |
| (2,803,415) |
| (3,431,295) | ||||
Operating lease liabilities | 94,020 | 85,313 | 185,789 |
| 170,331 | |||||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | — | 1,069,854 | — |
| 3,508,691 | |||||||
Other assets and liabilities | — | 995,143 | — |
| 687,353 | |||||||
EBITDA | 56,916,325 | 44,704,061 | 112,643,968 | 98,033,634 | ||||||||
Add: | ||||||||||||
Impairment of oil and natural gas properties |
| — |
| — |
| 5,963,575 |
| — | ||||
Unit-based compensation |
| 5,108,318 |
| 3,289,740 |
| 8,792,398 |
| 6,459,740 | ||||
Loss on extinguishment of debt | — |
| 480,244 |
| — |
| 480,244 | |||||
Loss (gain) on derivative instruments, net of settlements |
| 3,796,313 |
| (2,600,713) |
| 12,534,027 |
| (15,100,314) | ||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in Trust Account | — | (1,069,854) | — | (3,508,691) | ||||||||
General and administrative expense | — | 219,473 | — | 927,699 | ||||||||
Consolidated Adjusted EBITDA | 65,820,956 | 45,022,951 | 139,933,968 | 87,292,312 | ||||||||
Adjusted EBITDA attributable to non-controlling interest | (10,011,035) | (10,871,674) | (26,190,685) | (19,008,901) | ||||||||
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | 55,809,921 | 34,151,277 | 113,743,283 | 68,283,411 | ||||||||
Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ||||||||||||
Cash interest expense | 5,620,423 | 4,442,318 | 10,855,128 | 8,566,027 | ||||||||
Cash distribution on Series A preferred units | 4,110,950 | — | 7,911,246 | — | ||||||||
Cash income tax refund | — | — | — | (639,325) | ||||||||
Distribution on Class B units | 20,847 | 31,601 | 41,694 | 47,085 | ||||||||
Cash available for distribution on common units | $ | 46,057,701 | $ | 29,677,358 | $ | 94,935,215 | $ | 60,309,624 | ||||
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
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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 and six months ended June 30, 2024 and 2023 include the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”) in May 2023 and the acquisition of all of the issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in September 2023.
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.
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.
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 six months ended June 30, 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. We did not record an impairment on our oil and natural gas properties for the three months ended June 30, 2024 or three and six months ended June 30, 2023.
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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 June 30, | Six Months Ended June 30, | |||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||
Operating Results: | ||||||||||||
Revenue | ||||||||||||
Oil, natural gas and NGL revenues | $ | 76,959,173 | $ | 56,981,614 | $ | 164,458,682 | $ | 114,398,373 | ||||
Lease bonus and other income | 659,980 | 2,041,189 | 1,098,776 | 2,478,526 | ||||||||
(Loss) gain on commodity derivative instruments, net | (1,046,261) | 1,729,459 | (6,750,622) | 10,791,835 | ||||||||
Total revenues | 76,572,892 | 60,752,262 | 158,806,836 | 127,668,734 | ||||||||
Costs and expenses | ||||||||||||
Production and ad valorem taxes |
| 5,576,798 |
| 5,404,955 |
| 12,108,699 |
| 9,682,159 | ||||
Depreciation and depletion expense |
| 33,023,934 |
| 19,656,855 |
| 71,190,740 |
| 37,220,503 | ||||
Impairment of oil and natural gas properties |
| — |
| — |
| 5,963,575 |
| — | ||||
Marketing and other deductions |
| 3,827,646 |
| 2,907,459 |
| 8,390,590 |
| 5,669,498 | ||||
General and administrative expense |
| 10,252,123 |
| 7,925,159 |
| 19,700,004 |
| 16,203,426 | ||||
Consolidated variable interest entities related: | ||||||||||||
General and administrative expense | — | 219,473 | — |
| 927,699 | |||||||
Total costs and expenses |
| 52,680,501 |
| 36,113,901 |
| 117,353,608 |
| 69,703,285 | ||||
Operating income |
| 23,892,391 |
| 24,638,361 |
| 41,453,228 |
| 57,965,449 | ||||
Other (expense) income | ||||||||||||
Interest expense |
| (6,946,580) |
| (6,341,118) |
| (14,247,910) |
| (11,804,522) | ||||
Loss on extinguishment of debt | — |
| (480,244) |
| — |
| (480,244) | |||||
Other expense | — |
| (180,765) |
| — |
| (180,765) | |||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | — | 1,069,854 | — |
| 3,508,691 | |||||||
Net income before income taxes | 16,945,811 | 18,706,088 | 27,205,318 | 49,008,609 | ||||||||
Income tax expense | 1,759,282 | 909,057 | 2,681,850 | 2,312,040 | ||||||||
Net income | 15,186,529 | 17,797,031 | 24,523,468 | 46,696,569 | ||||||||
Distribution and accretion on Series A preferred units | (5,243,004) | — | (10,499,291) | — | ||||||||
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests | (1,512,360) | (4,297,442) | (2,403,209) | (9,860,860) | ||||||||
Distribution on Class B units | (20,847) | (31,601) | (41,694) | (47,085) | ||||||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | 8,410,318 | $ | 13,467,988 | $ | 11,579,274 | $ | 36,788,624 | ||||
Production Data: | ||||||||||||
Oil (Bbls) |
| 691,819 |
| 553,588 |
| 1,496,408 |
| 999,601 | ||||
Natural gas (Mcf) |
| 6,714,323 |
| 5,203,964 |
| 14,127,392 |
| 10,794,157 | ||||
Natural gas liquids (Bbls) |
| 383,092 |
| 230,241 |
| 841,339 |
| 432,946 | ||||
Combined volumes (Boe) (6:1) |
| 2,193,965 |
| 1,651,156 |
| 4,692,312 |
| 3,231,573 | ||||
Comparison of the Three Months Ended June 30, 2024 to the Three Months Ended June 30, 2023
Oil, Natural Gas and NGL Revenues
For the three months ended June 30, 2024, our oil, natural gas and NGL revenues were $77.0 million, an increase of $20.0 million from $57.0 million for the three months ended June 30, 2023. The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the three months ended June 30, 2024 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 2,193,965 Boe or 24,110 Boe/d, for the three months ended June 30, 2024,
28
an increase of 542,809 Boe or 5,965 Boe/d, from 1,651,156 Boe or 18,145 Boe/d, for the three months ended June 30, 2023. The increase in production for the three months ended June 30, 2024 was primarily attributable to production associated with the LongPoint Acquisition.
Our operators received an average of $77.20 per Bbl of oil, $2.10 per Mcf of natural gas and $24.75 per Bbl of NGL for the volumes sold during the three months ended June 30, 2024 compared to $71.91 per Bbl of oil, $2.22 per Mcf of natural gas and $24.46 per Bbl of NGL for the volumes sold during the three months ended June 30, 2023. These average prices received during the three months ended June 30, 2024 increased 7.4% or $5.29 per Bbl of oil and decreased 5.4% or $0.12 per Mcf of natural gas as compared to the three months ended June 30, 2023. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 11.2% or $8.27 per Bbl of oil and decrease of 4.2% or $0.09 per Mcf of natural gas for the comparable periods.
Lease Bonus and Other Income
Lease bonus and other income for the three months ended June 30, 2024 was $0.7 million, a decrease of $1.3 million from $2.0 million for the three months ended June 30, 2023. The decrease in lease bonus and other income was primarily related to a $0.9 million legal settlement received during the three months ended June 30, 2023.
(Loss) Gain on Commodity Derivative Instruments
Loss on commodity derivative instruments for the three months ended June 30, 2024 included $3.8 million of mark-to-market losses and $2.8 million of gains on the settlement of commodity derivative instruments compared to $2.6 million of mark-to-market gains and $0.9 million of losses on the settlement of commodity derivative instruments for the three months ended June 30, 2023. We recorded a mark-to-market loss for the three months ended June 30, 2024 as a result of the increase in oil and natural gas strip pricing from the three months ended March 31, 2024. We recorded a mark-to-market gain for the three months ended June 30, 2023 as a result of the maturity of derivative contracts with lower strike pricing, partially offset by realized losses on the settlement of commodity derivative instruments.
Production and Ad Valorem Taxes
Production and ad valorem taxes for the three months ended June 30, 2024 were $5.6 million, an increase of $0.2 million from $5.4 million for the three months ended June 30, 2023. The increase in production and ad valorem taxes was primarily attributable to production associated with the LongPoint Acquisition.
Depreciation and Depletion Expense
Depreciation and depletion expense for the three months ended June 30, 2024 was $33.0 million, an increase of $13.3 million from $19.7 million for the three months ended June 30, 2023. The increase in depreciation and depletion expense was due to the LongPoint Acquisition, which significantly 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 $15.01 for the three months ended June 30, 2024, an increase of $3.16 per barrel from the $11.85 average depletion rate per barrel for the three months ended June 30, 2023. The increase in the depletion rate was due to the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
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 June 30, 2024 were $3.8 million, an increase of $0.9 million from $2.9 million for the three months ended June 30, 2023. The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the LongPoint Acquisition.
29
General and Administrative Expenses
General and administrative expenses for the three months ended June 30, 2024 were $10.3 million, an increase of $2.4 million compared to $7.9 million for the three months ended June 30, 2023. 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 attributable to a $1.8 million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth.
Interest Expense
Interest expense for the three months ended June 30, 2024 was $6.9 million compared to $6.3 million for the three months ended June 30, 2023. The increase in interest expense was primarily due to an increase in the overall long-term debt balance as a result of borrowings associated with the LongPoint Acquisition, partially offset by a slight decrease in the weighted average interest rate on our outstanding borrowings for the three months ended June 30, 2024.
Income Tax Expense
We recorded an income tax expense of $1.8 million and $0.9 million for the three months ended June 30, 2024 and 2023, respectively.
Comparison of the Six Months Ended June 30, 2024 to the Six Months Ended June 30, 2023
Oil, Natural Gas and NGL Revenues
For the six months ended June 30, 2024, our oil, natural gas and NGL revenues were $164.5 million, an increase of $50.1 million from $114.4 million for the six months ended June 30, 2023. The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the six months ended June 30, 2024 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 4,692,312 Boe or 25,782 Boe/d, for the six months ended June 30, 2024, an increase of 1,460,739 Boe or 7,999 Boe/d, from 3,231,573 Boe or 17,783 Boe/d, for the six months ended June 30, 2023. The increase in production for the six months ended June 30, 2024 was primarily attributable to production associated with the MB Minerals Acquisition and the LongPoint Acquisition.
Our operators received an average of $76.87 per Bbl of oil, $2.03 per Mcf of natural gas and $24.72 per Bbl of NGL for the volumes sold during the six months ended June 30, 2024 compared to $72.84 per Bbl of oil, $2.89 per Mcf of natural gas and $24.02 per Bbl of NGL for the volumes sold during the six months ended June 30, 2023. These average prices received during the six months ended June 30, 2024 increased 5.5% or $4.03 per Bbl of oil and decreased 29.8% or $0.86 per Mcf of natural gas as compared to the six months ended June 30, 2023. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 6.6% or $4.96 per Bbl of oil and decrease of 12.1% or $0.29 per Mcf of natural gas for the comparable periods.
Lease Bonus and Other Income
Lease bonus and other income for the six months ended June 30, 2024 was $1.1 million, a decrease of $1.4 million from $2.5 million for the six months ended June 30, 2023. The decrease in lease bonus and other income was primarily related to a $0.9 million legal settlement received during the six months ended June 30, 2023.
(Loss) Gain on Commodity Derivative Instruments
Loss on commodity derivative instruments for the six months ended June 30, 2024 included $12.5 million of mark-to-market losses and $5.7 million of gains on the settlement of commodity derivative instruments compared to $15.1 million of mark-to-market gains and $4.3 million of losses on the settlement of commodity derivative instruments for the six months ended June 30, 2023. We recorded a mark-to-market loss for the six months ended June 30, 2024 as a result of
30
the increase in oil and natural gas strip pricing from the year ended December 31, 2023. We recorded a mark-to-market gain for the six months ended June 30, 2023 as a result of the maturity of derivative contracts with lower strike pricing, partially offset by realized losses on the settlement of commodity derivative instruments.
Production and Ad Valorem Taxes
Production and ad valorem taxes for the six months ended June 30, 2024 were $12.1 million, an increase of $2.4 million from $9.7 million for the six months ended June 30, 2023. The increase in production and ad valorem taxes was primarily attributable to production associated with the MB Minerals Acquisition and the LongPoint Acquisition.
Depreciation and Depletion Expense
Depreciation and depletion expense for the six months ended June 30, 2024 was $71.2 million, an increase of $34.0 million from $37.2 million for the six months ended June 30, 2023. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly 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 $15.13 for the six months ended June 30, 2024, an increase of $3.67 per barrel from the $11.46 average depletion rate per barrel for the six months ended June 30, 2023. The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
Impairment
We recorded an impairment on our oil and natural gas properties of $6.0 million during the six months ended June 30, 2024, as a result of our full cost ceiling analysis. 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. We did not record an impairment on our oil and natural gas properties for the six months ended June 30, 2023.
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 six months ended June 30, 2024 were $8.4 million, an increase of $2.7 million from $5.7 million for the six months ended June 30, 2023. The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the MB Minerals Acquisition and the LongPoint Acquisition.
General and Administrative Expenses
General and administrative expenses for the six months ended June 30, 2024 were $19.7 million, an increase of $3.5 million compared to $16.2 million for the six months ended June 30, 2023. 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 attributable to a $2.3 million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth.
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Interest Expense
Interest expense for the six months ended June 30, 2024 was $14.2 million compared to $11.8 million for the six months ended June 30, 2023. The increase in interest expense was primarily due to an increase in the overall long-term debt balance as a result of borrowings associated with the MB Minerals Acquisition and the LongPoint Acquisition.
Income Tax Expense
We recorded an income tax expense of $2.7 million and $2.3 million for the six months ended June 30, 2024 and 2023, 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 second quarter of 2024 for the repayment of $13.6 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the second quarter of 2024. 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.
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 issued 5,369,218 OpCo common units and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B units”) and 557,302 common units as
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partial consideration in connection with the MB Minerals Acquisition and we completed the LongPoint Acquisition partially with net proceeds from the private placement of Series A preferred units. 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 second quarter 2024 distributions.
Cash Flows
The table below presents our cash flows for the periods indicated.
Six Months Ended June 30, | ||||||
2024 |
| 2023 | ||||
Cash Flow Data: | ||||||
Net cash provided by operating activities | $ | 131,928,189 | $ | 78,572,135 | ||
Net cash (used in) provided by investing activities |
| (131,089) |
| 199,882,583 | ||
Net cash used in financing activities |
| (131,844,613) |
| (282,702,167) | ||
Net decrease in cash and cash equivalents | $ | (47,513) | $ | (4,247,449) | ||
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 six months ended June 30, 2024 were $131.9 million, an increase of $53.3 million compared to $78.6 million for the six months ended June 30, 2023.
Investing Activities
Cash flows used in investing activities for the six months ended June 30, 2024 were $0.1 million compared to $199.9 million of cash flows provided by investing activities for the six months ended June 30, 2023. For the six months ended June 30, 2024, cash flows used in investing activities included the purchase of equipment. For the six months ended June 30, 2023, cash flows provided by investing activities included $243.2 million of cash received from investment held in trust related to Kimbell Tiger Acquisition Corporation (“TGR”) and $0.9 million in cash received from the dissolution of TGR, partially offset by $44.2 million used primarily to fund costs associated with the MB Minerals Acquisition.
Financing Activities
Cash flows used in financing activities were $131.8 million for the six months ended June 30, 2024 compared to $282.7 million for the six months ended June 30, 2023. Cash flows used in financing activities for the six months ended June 30, 2024 consists primarily of $98.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $33.4 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and $0.3 million paid in connection with the redemption of Class B units, partially offset by $5.0 million of additional borrowings under our secured revolving credit facility.
Cash flows used in financing activities for the six months ended June 30, 2023 consists of $243.2 million of distributions to common unitholders of TGR, $66.7 million of distributions paid to holders common units, OpCo common units and Class B units, $22.5 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and a $4.8 million payment of loan origination costs, partially offset by $59.1 million of additional borrowings under our secured revolving credit facility and $0.3 million in Class B contributions.
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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 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 2023 Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
There have been no significant changes to our contractual obligations previously disclosed in our 2023 Form 10-K. As of June 30, 2024, 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 June 30, 2024, we had six 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 June 30, 2024, we had total borrowings outstanding under our secured revolving credit facility of $265.8 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 $2.7 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, 2023 through June 30, 2024. 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. Our disclosure controls and procedures are designed to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act 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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that as of June 30, 2024, our disclosure controls and procedures were effective in ensuring that all information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to our General Partner’s management, including its principal executive officer and principal financial officer, in a manner that allows timely decisions regarding required disclosure.
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 June 30, 2024 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 2023 Form 10-K. 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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Item 5. Other Information
Rule 10b5-1 Plans
On
Item 6. Exhibits
Exhibit |
| Description |
3.1 | — | |
3.2 | — | |
3.3 | — | |
3.4 | — | |
10.1+ | — | |
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: August 1, 2024 | By: | /s/ Robert D. Ravnaas | ||
Name: | Robert D. Ravnaas | |||
Title: | Chief Executive Officer and Chairman | |||
Principal Executive Officer | ||||
Date: August 1, 2024 |
| By: | /s/ R. Davis Ravnaas | |
Name: | R. Davis Ravnaas | |||
Title: | President and Chief Financial Officer | |||
Principal Financial Officer | ||||
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