KRP 10-K & 10-Q changes, risk factors and insider trading
Kimbell Royalty Partners, LP · NYSE · Crude Petroleum & Natural Gas · CIK 1657788 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.”
Removed heading “We identified a material weakness in our internal control over financial reporting that could have resulted in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations.”
Largest changes
“We identified a material weakness in our internal control over financial reporting that could have resulted in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations.”see in full comparison
“Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.”see in full comparison
“As more fully disclosed in Item 9A, “Controls and Procedures,” under the supervision and with the participation of our management, including our General Partner’s principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures and internal control over financial reporting. …”see in full comparison
“Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and increased volatility in commodity prices. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. …”see in full comparison
“Management has corrected the error and implemented a new control to ensure that changes in ownership of a consolidated subsidiary that is less than wholly owned are accounted for by adjusting the carrying value of non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the noncontrolling interest is adjusted will be recognized in equity attributable to the parent in accordance with ASC 810-10. …”see in full comparison
“We failed to maintain an effective control environment because we lacked sufficient oversight of the application of accounting guidance related to the changes in ownership of OpCo, which is a consolidated, less than wholly owned subsidiary. While this material weakness did not result in a material misstatement of our previously filed financial statements, there is a reasonable possibility that this control deficiency could have resulted in a material misstatement in our annual or interim consolidated financial statements that would not be detected. …”see in full comparison
Full comparison: every changed paragraph (19)
On September 13, 2023, we issued 325,000 preferred units representing limited partner interests in the Partnership. On May 7, 2025, we completed the redemption of 162,500 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. Our Series A preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for WTI, has ranged from a low of $(36.98)$47.47 per Bbl in AprilJanuary 20202021 to a high of $123.64 per Bbl in March 2022, and the Henry Hub spot market price of natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. On December 31, 2024,2025, the WTI posted price for crude oil was $72.44$57.26 per Bbl and the Henry Hub spot market price of natural gas was $3.40$4.00 per MMBtu. On February 10,17, 2025,2026, the WTI posted price for crude oil was $72.73$62.53 per Bbl and the Henry Hub spot market price of natural gas was $3.48$3.13 per MMBtu. Reductions in prices can be caused by many factors, including increases in oil and natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand, as well as actions by the OPEC to maintain or raise production levels. This environment could cause prices to remain at current levels or to fall to lower levels.
Concerns over global economic conditions, higher interest rates, supply chain constraints, energy costs, geopolitical issues, inflation, the availability and cost of credit, and slow economic growth in the United States can contribute to economic uncertainty and diminish expectations for the global economy. In addition, consequences associated with the ongoing invasion of Ukraine by Russia, the conflict in the Middle East, recent U.S. military action in Venezuela and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. With current global economic growth slowing, demand for oil, natural gas and NGL production has, in turn, softened. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash available for distribution on common units.
The marketability of our operators’ oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties.
The marketability of our operators’ oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. Neither we nor the operators of our properties control these third party transportation facilities and our operators’ access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our operators’ ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in our operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.
As of December 31, 2024, we had approximately $239.2 million in borrowings outstanding under our senior secured credit facility. As of February 21, 2025, we had approximately $308.2$441.5 million in borrowings outstanding under our senior secured credit facility. Our existing and any future indebtedness could have important consequences to us, including:
ProjectProspect areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025. We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million for the years ended December 31, 2024 and 2023, respectively, as a result of the decline in oil and natural gas prices. The Partnership did not record an impairment on its oil and natural gas properties for the year ended December 31, 2022.
Climate change and sustainability and other environmental considerations are a growing global concern with increasing focus from the public, investors and other stakeholders. In response2009, tothe findingsEPA found that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment,environment. Relying on this finding, referred to as the 2009 Endangerment Finding, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties. DuringOn hisFebruary presidency,12, President2026, Bidenthe EPA issued Executivea Ordersfinal seekingrule tothat adoptrescinded newthe 2009 Endangerment Finding and repealed all GHG emission standards for motor vehicles that directly relied on the 2009 Endangerment Finding. The impact from the February 2026 rescission on other GHG regulations andissued policiesunder tothe addressClean climateAir change and suspend, revise or rescind prior agency actionsAct that arerelied identified as conflicting withon the Biden2009 Administration’sEndangerment climate policies, including,Finding for example,legal directingsupport, including GHG regulations affecting the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permittingindustry, andis leasing practices. More recently, President Trump reversed certain climate-focused executive actions taken by President Biden. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.uncertain. Potential legal challenges to PresidentEPA’s Trump’srescission Executiveof Orders,the 2009 Endangerment Finding, or the imposition of additional regulatory burden on oil and gas development by state or local agencies,agencies orin anyresponse expansionto EPA’s repeal of federal climateGHG regulationsregulations, could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop our properties. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.
During his presidency, President Biden issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies, including, for example, directing the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. In his current presidential term, President Trump has reversed many climate-focused executive actions taken by President Biden. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Potential legal challenges to President Trump’s Executive Orders, imposition of additional regulatory burden on oil and gas development by state or local agencies, or any expansion of federal climate regulations could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop our properties. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.
Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. In line with a June 2017 announcement from President Trump, the United States withdrew from the Paris Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reversed this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021. In April 2021, President Biden announced a new, more rigorous nationally determined emissions reduction level of 50 percent to 52 percent from 2005 levels in economy-wide net GHG emissions by 2030, and in November 2021, the international community gathered again in Glasgow at COP26. During more recent COP meetings, including COP26, multiple efforts (not having the effect of law) were announced, including a call for countries to eliminate certain fossil fuel subsidies and pursue further action to reduce non-carbon dioxide GHG emissions. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative joined by more than 100 countries, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. In January 2025, President Trump ordered the U.S. Ambassador to the United Nations to submit a formal written notification of the United States’ withdrawal from the Paris Agreement.Agreement, which withdrawal by the United States became effective on January 27, 2026. Initiatives to implement pledges made at COP26,COP meetings, the Paris Agreement goals or other or similar initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators’ ability to economically develop our properties.
Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.
Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. Several recent tariff announcements by the U.S. federal government have been followed by announcements of limited exemptions and temporary pauses. These actions are unprecedented, have caused substantial uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods and commodities.
Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and increased volatility in commodity prices. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.
Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes, tariffs, trade agreements or policies, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.
We identified a material weakness in our internal control over financial reporting that could have resulted in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations.
As more fully disclosed in Item 9A, “Controls and Procedures,” under the supervision and with the participation of our management, including our General Partner’s principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures and internal control over financial reporting. Based on that evaluation, we concluded that our disclosure controls and procedures were not effective as of December 31, 2023, March 31, 2024, June 30, 2024 and September 30, 2024 due to material weaknesses in internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in our internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Partnership’s annual or interim financial statements will not be prevented or detected on a timely basis.
We failed to maintain an effective control environment because we lacked sufficient oversight of the application of accounting guidance related to the changes in ownership of OpCo, which is a consolidated, less than wholly owned subsidiary. While this material weakness did not result in a material misstatement of our previously filed financial statements, there is a reasonable possibility that this control deficiency could have resulted in a material misstatement in our annual or interim consolidated financial statements that would not be detected. Accordingly, we determined that this control deficiency constituted a material weakness.
Management has corrected the error and implemented a new control to ensure that changes in ownership of a consolidated subsidiary that is less than wholly owned are accounted for by adjusting the carrying value of non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the noncontrolling interest is adjusted will be recognized in equity attributable to the parent in accordance with ASC 810-10. During the fourth quarter of 2024, we completed our testing of effectiveness of the implemented procedures and controls and found them to be effective. As a result, we have concluded the material weakness has been remediated as of December 31, 2024.
Management's Discussion & Analysis (MD&A)
New heading “Government Legislation”
Removed heading “Equity Offering”
Largest changes
“We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural. As of December 31, 2024, the 12-month average prices of oil and natural gas were $75.48 per Bbl of oil and $2.13 per Mcf of natural gas. These prices represent a 3.5% and 19.3% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2023. …”see in full comparison
Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. Onsee in full comparisonJuneDecember13,16,2023,2025, we entered into a Second Amended and Restated Credit Agreement (the “Second 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.
“As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2022.”see in full comparison
see in full comparisonForOur average depletion rate per barrel was $13.22 for the year ended December 31,2023,2025,ouraaveragedecreasedepletionofrate per barrel increased by $4.19$1.58 per barrel from the$8.84$14.80 average depletion rate per barrel for the year ended December 31,2022.2024. Theincreasedecrease in the depletion rate was due to theMBimpairmentMineralsthatAcquisitionwas recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by theLongPointBoren Acquisition, whichsignificantlyincreased our net capitalized oil and natural gas properties.
“On January 9, 2025, we completed an underwritten public offering of 11,500,000 common units for net proceeds of approximately $163.6 million (the “2025 Equity Offering”). We used the net proceeds from the 2025 Equity Offering to purchase OpCo common units. The Operating Company ultimately used the net proceeds of the 2025 Equity Offering to fund the Boren Acquisition (as defined below).”see in full comparison
Full comparison: every changed paragraph (64)
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.
Equity Offering
On January 9, 2025, we completed an underwritten public offering of 11,500,000 common units for net proceeds of approximately $163.6 million (the “2025 Equity Offering”). We used the net proceeds from the 2025 Equity Offering to purchase OpCo common units. The Operating Company ultimately used the net proceeds of the 2025 Equity Offering to fund the Boren Acquisition (as defined below).
Acquisitions
On January 17, 2025, we completed the Boren Acquisition in a cash transaction valued at approximately $230.4 million. We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the 2025 Equity Offering. The oil and gas properties acquired are located under the Mabee Ranch in the Midland Basin in Texas. As of December 31, 2024, the acquired assets would have added 0.86 DUCs and net permitted locations on our acreage (0.64 net DUCs and 0.22 net permitted locations) and daily production of 1,864 Boe/d.
On February 27,26, 2025,2026, the Board of Directors declared a quarterly cash distribution of $0.40$0.37 per common unit and $0.357502 per OpCo common unit for the quarter ended December 31, 2024.2025. We intend to pay the distributions on March 25, 20252026 to common unitholders and OpCo common unitholders of record as of the close of business on March 18, 2025.2026.
The $0.012498 excluded from the OpCo common unit distribution corresponds to a tax refund received by us in the fourth quarter of 2025. Under the limited liability company agreement of the Operating Company, we do not reimburse the Operating Company for federal income tax refunds received by us.
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. InThese Januaryconflicts, 2025,along Israel and Hamas agreed to a ceasefire deal, however, there is no indication onwith the extentrecent ofU.S. themilitary ceasefire.action Thesein conflictsVenezuela, 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.
Government Legislation
On July 4, 2025, Public Law No. 119-21, commonly referred to as the One Big Beautiful Bill Act (the “Act”), was enacted by the U.S. government. Key provisions of the Act affecting us include: (i) the permanent reduction of the corporate tax rate, (ii) the permanent extension of 100% bonus depreciation for qualified property, and (iii) modifications to the calculation for excess business interest expense limitation under § 163(j) to adjusted taxable income calculation on the business interest expense limitation. In accordance with ASC Topic 740, Income Taxes, we have recognized the effects of the new tax law in the period of enactment. The impact of the Act for the quarter ended September 30, 2025, the reporting period that included the enactment date, resulted in a reduction to current income tax expense, primarily due to the changes to the 163(j) interest limitation.
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”).
The Baker Hughes United States rotary rig count decreased 8.0% to 527 active land rigs at December 31, 2025 compared to 573 active land rigs at December 31, 2024. The decrease in rig count is primarily related to a decrease in the average prices received for oil, partially offset by an increase in the average price received for natural gas, coupled with domestic and international uncertainties, as noted above.
The Baker Hughes United States Rotary Rig count decreased 4.8% to 573 active land rigs at December 31, 2024 compared to 602 active land rigs at December 31, 2023. While the United States Rotary Rig count decreased year over year, overall production is not decreasing, indicating improved efficiencies are allowing sustained production from fewer rigs.
The 602573 active rig count at December 31, 20232024 decreased 21%4.8% compared to 762602 active land rigs at December 31, 2022.2023. The overall decrease in rig count at December 31, 20232024 compared December 31, 20222023 iswas primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.
Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the years ended December 31, 2024,2025, 2024 and 2023 include the acquisition of mineral and 2022royalty includeinterests from Boren Minerals (the “Boren Acquisition”), the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”), and 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”) and the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”).
We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025. We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas.
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural. As of December 31, 2024, the 12-month average prices of oil and natural gas were $75.48 per Bbl of oil and $2.13 per Mcf of natural gas. These prices represent a 3.5% and 19.3% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2023. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2022.
For the year ended December 31, 2024,2025, our oil, natural gas and NGL revenues were $304.6$317.5 million, an increase of $37.0$12.9 million from $267.6$304.6 million for the year ended December 31, 2023.2024. The increase in oil, natural gas and NGL revenues was primarily related to an increase in the average prices received for natural gas coupled with an increase in combined production volumes for the year ended December 31, 20242025, partially offset by a decrease in the average prices received for oil and NGLs, as discussed below.
Our revenues for the year ended December 31, 20232024 decreasedincreased by $14.4$37.0 million, from $282.0$267.6 million for the year ended December 31, 2022.2023. The decreaseincrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the year ended December 31, 20232024 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 9,402,348 Boe or 25,760 Boe/d, for the year ended December 31, 2025, an increase of 300,603 Boe or 892 Boe/d, from 9,101,745 Boe or 24,868 Boe/d, for the year ended December 31, 2024,2024. anThe increase ofin 1,729,123production Boe or 4,603 Boe/d, from 7,372,622 Boe or 20,265 Boe/d,volumes for the year ended December 31, 2023. The increase in production for the year ended December 31, 20242025 was primarily attributable to production associated with the MBBoren Minerals Acquisition and the LongPoint Acquisition, which included a full year of production for the year ended December 31, 2024, compared to a partial year of production for the year ended December 31, 2023.Acquisition.
Our production volumes for the year ended December 31, 20232024 increased by 1,814,7501,729,123 Boe or 5,2404,603 Boe/d, from 5,557,8727,372,622 Boe or 15,025,20,265 Boe/d, for the year ended December 31, 2022.2023. The increase in production for the year ended December 31, 20232024 was primarily attributable to production associated with the HatchMB Minerals Acquisition and the LongPoint Acquisition, which included a full year of production for the year ended December 31, 2023,2024, compared to approximatelya threepartial monthsyear of production for the year ended December 31, 2022, the MB Minerals Acquisition, and to a lesser extent, production associated with the LongPoint Acquisition.2023.
Our operators received an average of $63.84 per Bbl of oil, $2.93 per Mcf of natural gas and $23.15 per Bbl of NGL for the volumes sold during the year ended December 31, 2025 and $75.98 per Bbl of oil, $1.82 per Mcf of natural gas and $23.34 per Bbl of NGL for the volumes sold during the year ended December 31, 2024 and $76.55 per Bbl of oil, $2.55 per Mcf of natural gas and $23.01 per Bbl of NGL for the volumes sold during the year ended December 31, 2023.2024. The year ended December 31, 20242025 decreased 0.7%16.0% or $0.57$12.14 per Bbl of oil and 28.6%increased 61.0% or $0.73$1.11 per Mcf of natural gas compared to the year ended December 31, 2023.2024. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 1.2%14.7% or $0.95$11.24 per Bbl of oil and 13.4%increase of 60.7% or $0.34$1.33 per Mcf of natural gas for the comparable periods.
For the year ended December 31, 20242025 lease bonus and other income was $6.0$4.3 million, ana increasedecrease of $0.4$1.7 million compared to $5.6$6.0 million for the year ended December 31, 2023.2024. The increasedecrease in lease bonus and other income is primarilywas due to a large number lease bonusesbonus received during the year ended December 31, 2024.
Our lease bonus and other income for the year ended December 31, 20232024 increased by $2.5$0.4 million compared to $3.1$5.6 million for the year ended December 31, 2022.2023. The increase in lease bonus and other income is primarily relateddue to legala settlementslarge number of lease bonuses received during the year ended December 31, 2023.2024.
Gain (Loss) Gain on Commodity Derivative Instruments
Loss on commodity derivative instruments for the year ended December 31, 2024 included $12.2 million of mark-to-market losses and $10.9 million of gains on the settlement of commodity derivative instruments compared to $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments for the year ended December 31, 2023. We recorded a mark-to-market loss for the year ended December 31, 2024 as a result of the increase in oil and natural gas strip pricing from the year ended December 31, 2023, offset by realized gains on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was partially offset by the realized losses on the settlement of commodity derivative instruments.
LossGain on commodity derivative instruments for the year ended December 31, 20222025 included $16.0$7.2 million of mark-to-market gains and $53.0$4.9 million of lossesgains on the settlement of commodity derivative instruments.instruments compared to $12.2 million of mark-to-market losses and $10.9 million of gains on the settlement of commodity derivative instruments for the year ended December 31, 2024. We recorded a mark-to-market gain for the year ended December 31, 20222025 as a result of the maturity of derivative contracts with lower strike pricing. ThisWe gainrecorded wasa mark-to-market loss for the year ended December 31, 2024 as a result of the increase in oil and natural gas strip pricing from the year ended December 31, 2023, offset by therealized lossesgains on the settlement of commodity derivative instruments.
Gain on commodity derivative instruments for the year ended December 31, 2023 included $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was partially offset by the realized losses on the settlement of commodity derivative instruments.
Production and ad valorem taxes for the yearyears ended December 31, 2025 and 2024 remained flat at $20.4 million, compared to $20.3 million for the year ended December 31, 2023.million.
For the year ended December 31, 2024, production and ad valorem taxes remained relatively flat compared to $20.3 million for the year ended December 31, 2023.
For the year ended December 31, 2023, production and ad valorem taxes increased by $4.1 million from $16.2 million for the year ended December 31, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition. The increase was partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.
Depreciation and depletion expense for the year ended December 31, 20242025 was $135.1$124.6 million, ana increasedecrease of $38.6$10.5 million from $96.5$135.1 million for the year ended December 31, 2023.2024. The increasedecrease in depreciation and depletion expense was due to the MBimpairment Mineralsthat Acquisitionwas recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the LongPointBoren 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 unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $14.80 for the year ended December 31, 2024, an increase of $1.77 per barrel from the $13.03 average depletion rate per barrel for the year ended December 31, 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.
ForOur average depletion rate per barrel was $13.22 for the year ended December 31, 2023,2025, oura averagedecrease depletionof rate per barrel increased by $4.19$1.58 per barrel from the $8.84$14.80 average depletion rate per barrel for the year ended December 31, 2022.2024. The increasedecrease in the depletion rate was due to the MBimpairment Mineralsthat Acquisitionwas recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the LongPointBoren Acquisition, which significantly increased our net capitalized oil and natural gas properties.
For the year ended December 31, 2024, our average depletion rate per barrel increased by $1.77 per barrel from the $13.03 average depletion rate per barrel for the year ended December 31, 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.
We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025.
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas. As of December 31, 2024, the 12-month average prices of oil and natural gas were $75.48 per Bbl of oil and $2.13 per Mcf of natural gas. These prices represent a 3.5% and 19.3% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2023.
As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2022.
Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the year ended December 31, 20242025 wereremained $16.1relatively million,flat anat increase of $3.5$16.4 million fromcompared $12.6to $16.1 million for the year ended December 31, 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, which included a full year of marketing and other deductions for the year ended December 31, 2024, compared to a partial year of marketing and other deductions for the year ended December 31, 2023.2024.
Marketing and other deductions for the year ended December 31, 2024 increased by $3.5 million from $12.6 million for the year ended December 31, 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, which included a full year of marketing and other deductions for the year ended December 31, 2024, compared to a partial year of marketing and other deductions for the year ended December 31, 2023.
Marketing and other deductions for the year ended December 31, 2023 decreased by $0.8 million from $13.4 million for the year ended December 31, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition.
General and administrative expenses for the year ended December 31, 2024 were $38.5 million, an increase of $2.8 million from $35.7 million for the year ended December 31, 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 $3.3 million increase in unit-based compensation expense, partially offset by a $0.4 million decrease in cash expenses.
General and administrative expenses for the year ended December 31, 20232025 increasedwere by$39.7 $6.6million, an increase of $1.2 million from $29.1$38.5 million for the year ended December 31, 2022.2024. The increase in general and administrative expenses was attributable to a $2.0 million increase in unit-based compensation expense, expenses related to a one-time cash bonus paid to employees and cash general and administrative expenses resulting from an increase in our costs associated with companyPartnership growth.
General and administrative expenses for the year ended December 31, 2024 increased by $2.8 million from $35.7 million for the year ended December 31, 2023. The increase in general and administrative expenses was attributable to a $3.3 million increase in unit-based compensation expense, partially offset by a $0.4 million decrease in cash expenses.
Interest expense for the year ended December 31, 2024 was $26.7 million as compared to interest expense of $26.0 million for the year ended December 31, 2023. The increase in interest expense was attributable 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 in May 2023 and September 2023, respectively. This increase was partially offset by a decrease in the weighted average interest rate on our outstanding borrowings from 8.62% at December 31, 2023 to 8.42% at December 31, 2024, coupled with the repayment of $60.0 million on our secured revolving credit facility for the year ended December 31, 2024.
Interest expense for the year ended December 31, 20232025 increasedwas by $12.2$34.5 million as compared to interest expense of $13.8$26.7 million for the year ended December 31, 2022.2024. The increase in interest expense was primarily due to an increase in the weighted average interest rate on our outstanding borrowings from 5.28% at December 31, 2022 to 8.62% at December 31, 2023. Also contributing to the increase in interest expense was an increase in the overall long-term debt balance as a result of additional borrowings associatedto withcomplete the Hatchpartial Acquisition,redemption of the MBSeries MineralsA Acquisitionpreferred units and the LongPointBoren Acquisition.
Interest expense for the year ended December 31, 2024 increased by $0.7 million compared to interest expense of $26.0 million for the year ended December 31, 2023. The increase in interest expense was attributable 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 in May 2023 and September 2023, respectively. This increase was partially offset by a decrease in the weighted average interest rate on our outstanding borrowings from 8.62% at December 31, 2023 to 8.42% at December 31, 2024, coupled with the repayment of $60.0 million on our secured revolving credit facility for the year ended December 31, 2024.
Income Tax (Benefit) Expense
For the year ended December 31, 2024,2025 we recognized an income tax benefit of $0.8$1.3 million, resulting in an effective tax benefit of 7.49%,1.33%, compared to an income tax benefit of $0.8 million for the year ended December 31, 2024, resulting in an effective tax rate of 7.49%. We recognized an income tax expense of $3.8 million for the year ended December 31, 2023, resulting in an effective tax rate of 4.34%. We recognized an income tax expense of $2.7 million for the year ended December 31, 2022, resulting in an effective tax rate of 2.05%.
Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. On JuneDecember 13,16, 2023,2025, we entered into a Second Amended and Restated Credit Agreement (the “Second 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.
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, the purchase price paid in the Boren Acquisition was partially funded by the proceeds from the underwritten public offering of 11,500,000 common units which resulted in net proceeds of approximately $163.6 million (the “2025 Equity Offering”), we issued 5,369,218 OpCo common units and an equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals Acquisition and wethe completedpurchase price paid in the LongPoint Acquisition was partially withfunded by the net proceeds from the Preferred Unit Transaction. 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—Fourth Quarter Distributions” above for discussion of our fourth quarter 20242025 distributions.
Operating cash flow is impacted by many variables, the most significant of which are the 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 we receive from our operators on those volumes. 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 year ended December 31, 20242025 were $250.9$246.5 million, ana increasedecrease of $76.6$4.4 million compared to $174.3$250.9 million for the year ended December 31, 2023.2024.
Cash flows used in investing activities for the year ended December 31, 20242025 were $0.2$223.5 million compared to $246.7$0.2 million for the year ended December 31, 2023.2024. For the year ended December 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition. For the year ended December 31, 2024, cash flows used in investing activities included the purchase of equipment.
Cash flows used in investing activities for the year ended December 31, 2022 include $236.9 million of investments held in marketable securities related to TGR, $141.3 million used primarily to fund the Hatch Acquisition and $0.2 million used to fund the purchase of equipment, partially offset by $3.6 million in cash distributions received in connection to the joint venture with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP (the “Joint Venture”).
Cash flows used in financing activities were $247.5$13.2 million for the year ended December 31, 20242025 compared to $78.4$247.5 million of cash flows provided by financing activities for the year ended December 31, 2023.2024. Cash flows used in financing activities for the year ended December 31, 20242025 consists primarily of $187.2$179.9 million used to redeem a portion of the Series A preferred units, $187.3 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $60.0$493.3 million used to repay borrowings under our secured revolving credit facility,facility $4.9and $5.1 million of restricted units repurchased for tax withholding and $0.3 million paid in connection with the redemption of Class B units,withholding, partially offset by $5.0$163.6 million in proceeds from the 2025 Equity Offering and $695.6 million of additional borrowings under our secured revolving credit facility.
Cash flows used in financing activities for the year ended December 31, 2024 consists primarily of $187.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $60.0 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 provided by financing activities for the year ended December 31, 2022 consists of $227.6 million in proceeds from the TGR initial public offering (these proceeds were held in trust for the benefit of public stockholders and not available to KRP), $199.2 million of additional borrowings under our secured revolving credit facility, $116.1 million in proceeds from the 2022 equity offering and $0.4 million in contributions from Class B unitholders, partially offset by $183.3 million used to repay borrowings under our secured revolving credit facility, $126.8 million of distributions paid to holders of common units, OpCo common units and Class B units, $3.3 million of restricted units repurchased for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units and $0.7 million payment of loan origination costs.
During the year ended December 31, 2025, we paid approximately $222.8 million primarily to fund the Boren Acquisition. During the year ended December 31, 2023, we paid approximately $490.7 million primarily to fund the MB Minerals Acquisition and the LongPoint Acquisition. During the year ended December 31, 2022, we paid approximately $141.3 million primarily to fund the Hatch Acquisition.
On JuneDecember 13,16, 2023,2025, we entered into ana AmendedSecond and Restated Credit Agreement (the “A&R Credit Agreement”),Agreement, which amended and restated our existing Amended and Restated Credit Agreement, dated as of JanuaryJune 11,13, 20172023 (as amended on July 12,24, 2018,2023, December 8, 2020, June 7, 20222023, and DecemberMay 15,1, 20222025). The Second 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$1.5 millionbillion with an initial borrowing base of $400.0$625.0 million and an initial aggregate elected commitments amount of up to $400.0$625.0 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 Second A&R Credit Agreement to JuneDecember 7,16, 2027.2030.
What changed in the latest 10-Q
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 2025 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.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
New heading “Conversion of Class B Units to Common Units”
New heading “Comparison of the Six Months Ended June 30, 2026 to the Six Months Ended June 30, 2025”
New heading “Oil, Natural Gas and NGL Revenues”
New heading “Lease Bonus and Other Income”
New heading “(Loss) Gain on Commodity Derivative Instruments”
New heading “Production and Ad Valorem Taxes”
New heading “Depreciation and Depletion Expense”
New heading “Marketing and Other Deductions”
New heading “General and Administrative Expenses”
New heading “Interest Expense”
New heading “Income Tax Expense”
Largest changes
see in full comparisonIn 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. These conflicts, along with theThe recent U.S. military action inVenezuelaIranand Iran, and the applicable sanctions imposed in response havehas led to regional instability and caused dramatic fluctuations in global financial markets andhaveincreased 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 adverse 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.
“Comparison of the Six Months Ended June 30, 2026 to the Six Months Ended June 30, 2025”see in full comparison
Full comparison: every changed paragraph (65)
As of MarchJune 31,30, 2026, we owned mineral and royalty interests in approximately 12.312.5 million gross acres and overriding royalty interests in approximately 4.74.8 million gross acres, with approximately 54%55% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of MarchJune 31,30, 2026, 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 133,000134,000 gross wells, including over 53,00054,000 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 MarchJune 31,30, 2026:
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 MarchJune 31,30, 2026:
On MayAugust 7, 2026, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.41$0.47 per common unit representing limited partner interests in the Partnership (“common unit”) and $0.496665 per common unit of the Operating Company (“OpCo common unit”) for the quarter ended MarchJune 31,30, 2026. We intend to pay the distributions on MayAugust 27,24, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on MayAugust 19,17, 2026.
As to us, $0.026665 of the OpCo common unit distribution corresponds to a tax payment made by us in the second quarter of 2026. Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.
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 $2.4 million for the quarter ended MarchJune 31,30, 2026. We intend to pay the distribution subsequent to MayAugust 7, 2026 and prior to the distribution on the common units and OpCo common units.
Acquisitions
On June 22, 2026, we completed the acquisition of mineral and royalty interests from Mesa Visa Royalties, LLC and certain of its affiliates (the “Mesa Acquisition) in a transaction valued at approximately $147.0 million, including transaction costs and certain customary post-closing adjustments. The aggregate consideration for the Mesa Acquisition consisted of approximately $44.0 million in cash and the issuance of 6,929,000 OpCo common units and an equal number of Class B units representing limited partner interests in Kimbell (“Class B units”). We funded the cash consideration of the purchase price with borrowings under our secured revolving credit facility. The oil and gas properties are located in Loving, Ward, Upton, Howard, Glasscock, Martin, Winkler, Culberson, Midland, Pecos, Borden, Reagan, Reeves and Dawson Counties, Texas, and Eddy and Lea Counties, New Mexico.
On July 16, 2026, we, Opco, Kimbell Royalty Holdings, LLC (“KRH”), Kimbell Intermediate Holdings, LLC (“Intermediate”), KRP Legacy NBR, LLC (“KRP Legacy”), and Kimbell Crest Minerals LLC (“Kimbell Crest” and, together with us, Opco, KRH, Intermediate and KRP Legacy, the “Buyer Parties”), entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Rivercrest Capital Partners LP (“Rivercrest Capital”), Rivercrest Capital Partners II LP (“Rivercrest Capital II”), Cupola Royalty Direct, LLC (“Cupola” and, together with Rivercrest Capital and Rivercrest Capital II, the “Sellers”). The transactions contemplated by the Purchase Agreement are referred to as the “Dropdown.”
The Buyer Parties have agreed to acquire (a) certain mineral interests, overriding royalty interests, royalty interests and other interests in oil and gas properties from the Sellers and (b) certain partnership interests in OGM Partners I, and RCPTX, Ltd, that are not already owned by the Buyer Parties. The aggregate consideration payable by the Buyer Parties will be approximately $75.0 million in cash and the issuance of 9.5 million Opco units and an equal number of Class B units to the Sellers or their designees.
Completion of the Dropdown is subject to the satisfaction or waiver of certain customary closing conditions as set forth in the Purchase Agreement. The Dropdown is expected to close on or about August 21, 2026, with an effective date of June 1, 2026.
Conversion of Class B Units to Common Units
On July 22, 2026, we issued 2,243,716 common units to an existing OpCo unitholder in exchange for 2,243,716 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018, by and among us, the General Partner, the Operating Company and the other holders of OpCo common units and Class B units from time to time party thereto (the “Exchange Agreement”).
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. These conflicts, along with theThe recent U.S. military action in VenezuelaIran and Iran, and the applicable sanctions imposed in response havehas 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 adverse 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.
On July 4, 2025, Public Law No. 119-21, commonly referred to as the One Big Beautiful Bill Act (the “Act”), was enacted by the U.S. government. Key provisions of the Act effecting the us include: (i) the permanent reduction of the corporate tax rate, (ii) the permanent extension of 100% bonus depreciation for qualified property, and (iii) modifications to the calculation for excess business interest expense limitation under § 163(j) to adjusted taxable income calculation on the business interest expense limitation. In accordance with ASC Topic 740, Income Taxes, we have recognized the effects of the new tax law in the period of enactment. The impact of the Act for the quarter ended MarchJune 31,30, 2026 resulted in a reduction to current income tax expense, primarily due to the changes to the 163(j) interest limitation.
On AprilJuly 27, 2026, the West Texas Intermediate posted price for crude oil was $99.89$84.25 per Bbl and the Henry Hub spot market price of natural gas was $2.72$2.63 per MMBtu.
The Baker Hughes United States Rotary Rig count increased by 5.3% to 561 active land rigs at June 30, 2026 compared to 533 active land rigs at June 30, 2025. The 561 active land rigs at June 30, 2026 increased by 5.8% compared to 530 active land rigs at March 31, 2026. The increase in rig count is primarily related to the energy crisis in the Middle East and surging global oil prices.
The Baker Hughes United States Rotary Rig count decreased by 7.8% to 530 active land rigs at March 31, 2026 compared to 575 active land rigs at March 31, 2025. The 530 active land rigs at March 31, 2026 increased slightly compared to 527 active land rigs at December 31, 2025. The decrease in rig count is primarily related to domestic and international uncertainties, as noted above.
We have entered into oil and natural gas commodity derivative agreements, which extend through MarchJune 2028, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests. For further discussion on our commodity derivative agreements, see Note 5—Derivatives.
Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three and six months ended MarchJune 31,30, 2026 and 2025 include the Mesa Acquisition in June 2026 and the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in January 2025.
Accounting standards require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience significant downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. We did not record an impairment on our oil and natural gas properties for the three and six months ended MarchJune 31,30, 2026 and 2025.
Comparison of the Three Months Ended MarchJune 31,30, 2026 to the Three Months Ended MarchJune 31,30, 2025
For the three months ended MarchJune 31,30, 2026, our oil, natural gas and NGL revenues were $82.9$103.0 million, aan decreaseincrease of $7.1$28.3 million from $90.0$74.7 million for the three months ended MarchJune 31,30, 2025. The decreaseincrease in oil, natural gas and NGL revenues was primarily related to a decrease in the average prices received for natural gas and NGLs, partially offset by and an increase in the average prices received for oiloil, coupled with a slight increase in production volumes for the three months ended MarchJune 31,30, 2026, 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 2,296,9702,350,521 Boe or 25,52225,830 Boe/d, for the three months ended MarchJune 31,30, 2026, an increase of 1,88043,237 Boe or 21475 Boe/d, from 2,295,0902,307,284 Boe or 25,50125,355 Boe/d, for the three months ended MarchJune 31,30, 2025.
Our operators received an average of $69.55$97.85 per Bbl of oil, $3.15$2.08 per Mcf of natural gas and $23.93$27.67 per Bbl of NGL for the volumes sold during the three months ended MarchJune 31,30, 20262026, compared to $69.27$63.52 per Bbl of oil, $3.87$2.34 per Mcf of natural gas and $27.99$23.56 per Bbl of NGL for the volumes sold during the three months ended MarchJune 31,30, 2025. The average priceprices received during the three months ended MarchJune 31,30, 2026 increased 0.4%54.0% or $0.28$34.33 per Bbl of oil,oil and decreased 11.1% or $0.26 per Mcf of natural gas, which is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 1.3%48.1% or $0.96$31.08 per Bbl of oil.oil Theand averagedecrease priceof received during the three months ended March 31, 2026 decreased 18.6%7.5% or $0.72$0.24 per Mcf of natural gas as compared to the three months ended March 31, 2025 as a result of lower differentials in the Permian Basin.gas.
Lease bonus and other income for the three months ended MarchJune 31,30, 2026 was $1.3$3.3 million, an increase of $1.0$0.8 million compared to $0.3$2.5 million for the three months ended MarchJune 31,30, 2025. The increase in lease bonus and other income was due to a large number of lease bonuses received during the three months ended MarchJune 31,30, 2026.
LossGain on Commodity Derivative Instruments
LossGain on commodity derivative instruments for the three months ended MarchJune 31,30, 2026 included $18.8$9.3 million of mark-to-market lossesgains and $0.1$3.2 million of gainslosses on the settlement of commodity derivative instruments compared to $7.0$8.5 million of mark-to-market lossesgains and $0.9$0.8 million of gains on the settlement of commodity derivative instruments for the three months ended MarchJune 31,30, 2025. We recorded a mark-to-market lossesgain for the both the three months ended MarchJune 31,30, 2026 and 2025 as a result of an increase in strip pricing from the previous quarter, partially offset by gains on the settlementmaturity of commodity derivative instruments.contracts with lower strike pricing.
Production and ad valorem taxes for the three months ended MarchJune 31,30, 2026 were $5.9$8.2 million, an increase of $0.5$2.5 million compared to $5.4$5.7 million for the three months ended MarchJune 31,30, 2025. The increase in production and ad valorem taxes was primarily attributable to the increase in production volumes along with an increase in the average prices received for oil, partially offset by a decrease in the average prices received for natural gas and NGLsoil for the three months ended MarchJune 31,30, 2026.2026, and to a lesser extent, the slight increase in production volumes.
Depreciation and depletion expense for the three months ended MarchJune 31,30, 2026 was $29.3$30.2 million, a decrease of $1.8$0.3 million from $31.1$30.5 million for the three months ended MarchJune 31,30, 2025. The decrease in depreciation andthe depletion expenserate was due to the gradual reduction in the depletable base of our oil and natural gas properties, partially offset by the Mesa Acquisition, which increased our net capitalized oil and natural gas properties.
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $12.74$12.84 for the three months ended MarchJune 31,30, 2026, a decrease of $0.78$0.32 per barrel from the $13.52$13.16 average depletion rate per barrel for the three months ended MarchJune 31,30, 2025. The decrease in the depletion rate was due to the gradual reduction in the depletable base of our oil and natural gas properties, partially offset by the Mesa Acquisition, which increased our net capitalized oil and natural gas properties.
Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended MarchJune 31,30, 2026 were $5.2$4.2 million, an increase of $0.7$1.2 million compared to $4.5$3.0 million for the three months ended MarchJune 31,30, 2025. The increase in marketing and other deductions was primarily related to the increase in production volumes along with an increase in the average prices received for oil, partially offset by a decrease in the average prices received for natural gas and NGLsoil for the three months ended MarchJune 31,30, 2026.2026, and to a lesser extent, the slight increase in production volumes.
General and administrative expenses for the three months ended MarchJune 31,30, 2026 were $9.4$10.2 million, aan decreaseincrease of $0.2$0.6 million compared to $9.6 million for the three months ended MarchJune 31,30, 2025. 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 decreaseincrease in general and administrative expenses was primarily attributable to an overall decreaseincrease in cash general and administrative expenses,expenses partiallyand offseta by$0.2 anmillion increase in unit-based compensation expense.
Interest expense for the three months ended MarchJune 31,30, 2026 was $8.2$8.4 million, compared to $6.6$8.9 million for the three months ended MarchJune 31,30, 2025. The increasedecrease in interest expense was primarily due to ana increase1.06% decrease in the overallweighted debtaverage balanceinterest asrate a result of additional borrowings to completefrom the partialthree redemptionmonths ofJune the30, Series A preferred units.2025.
We recorded an income tax expense of $0.7$4.0 million and $1.1$2.2 million for the three months ended MarchJune 31,30, 2026 and 2025, respectively.
Comparison of the Six Months Ended June 30, 2026 to the Six Months Ended June 30, 2025
Oil, Natural Gas and NGL Revenues
For the six months ended June 30, 2026, our oil, natural gas and NGL revenues were $185.9 million, an increase of $21.3 million from $164.6 million for the six months ended June 30, 2025. The increase in oil, natural gas and NGL revenues was primarily related to an increase in the average prices received for oil, coupled with a slight increase in production volumes for the six months ended June 30, 2026, 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 4,647,491 Boe or 25,677 Boe/d, for the six months ended June 30, 2026, an increase of 45,117 Boe or 250 Boe/d, from 4,602,374 Boe or 25,427 Boe/d, for the six months ended June 30, 2025.
Our operators received an average of $84.12 per Bbl of oil, $2.61 per Mcf of natural gas and $25.81 per Bbl of NGL for the volumes sold during the six months ended June 30, 2026 compared to $66.36 per Bbl of oil, $3.11 per Mcf of natural gas and $25.76 per Bbl of NGL for the volumes sold during the six months ended June 30, 2025. The average price received during the six months ended June 30, 2026 increased 26.8% or $17.76 per Bbl of oil, which is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 23.7% or $16.17 per Bbl of oil. The average price received during the six months ended June 30, 2026 decreased 16.1% or $0.5 per Mcf of natural gas as compared to the six months ended June 30, 2025 as a result of lower differentials in the Permian Basin.
Lease Bonus and Other Income
Lease bonus and other income for the six months ended June 30, 2026 was $4.7 million, an increase of $1.9 million compared to $2.8 million for the six months ended June 30, 2025. The increase in lease bonus and other income was due to an increase in activity during the six months ended June 30, 2026.
(Loss) Gain on Commodity Derivative Instruments
Loss on commodity derivative instruments for the six months ended June 30, 2026 included $9.5 million of mark-to-market losses and $3.1 million of losses on the settlement of commodity derivative instruments compared to $1.5 million of mark-to-market gains and $1.8 million of gains on the settlement of commodity derivative instruments for the six months ended June 30, 2025. We recorded a mark-to-market loss for the six months ended June 30, 2026 as a result of an increase in strip pricing from the previous quarter. We recorded a mark-to-market gain for the six months ended June 30, 2025 as a result of the maturity of derivative contracts with lower strike pricing.
Production and Ad Valorem Taxes
Production and ad valorem taxes for the six months ended June 30, 2026 were $14.1 million, an increase of $3.0 million from $11.1 million for the six months ended June 30, 2025. The increase in production and ad valorem taxes was primarily attributable to the increase in the average prices received for oil for the six months ended June 30, 2026, and to a lesser extent, the slight increase in production volumes.
Depreciation and Depletion Expense
Depreciation and depletion expense for the six months ended June 30, 2026 was $59.5 million, a decrease of $2.1 million from $61.6 million for the six months ended June 30, 2025. The decrease in the depletion rate was due to the gradual reduction in the depletable base of our oil and natural gas properties, partially offset by the Mesa Acquisition, which increased our net capitalized oil and natural gas properties.
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $12.79 for the six months ended June 30, 2026, a decrease of $0.55 per barrel from the $13.34 average depletion rate per barrel for the six months ended June 30, 2025. The decrease in the depletion rate was due to the gradual reduction in the depletable base of our oil and natural gas properties, partially offset by the Mesa Acquisition, which 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 six months ended June 30, 2026 was $9.3 million, an increase of $1.8 million compared to $7.5 million for the six months ended June 30, 2025. The increase in marketing and other deductions was primarily related to the increase in the average prices received for oil for the six months ended June 30, 2026, and to a lesser extent, the slight increase in production volumes.
General and Administrative Expenses
General and administrative expenses for the six months ended June 30, 2026 were $19.6 million, an increase of $0.4 million compared to $19.2 million for the six months ended June 30, 2025. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to an increase in unit-based compensation expense.
Interest Expense
Interest expense for the six months ended June 30, 2026 was $16.6 million, compared to $15.6 million for the six months ended June 30, 2025. The increase in interest expense was primarily due to an increase in the overall debt balance as a result of additional borrowings to complete the Boren Acquisition, the partial redemption of the Series A preferred units and the Mesa Acquisition, partially offset by a 1.02% decrease in the weighted average interest rate from the six months ended June 30, 2025.
Income Tax Expense
We recorded an income tax expense of $4.7 million and $3.3 million for the six months ended June 30, 2026 and 2025, respectively.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the firstsecond quarter of 2026 for the repayment of $14.5$17.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the firstsecond quarter of 2026. 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.
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 6,929,000 OpCo common units and an equal number of Class B units as partial consideration in connection with the Mesa Acquisition and we completed the Boren Acquisition partially with net proceeds from an underwritten public offering of 11,500,000 common units (the “2025 Equity Offering”). The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our firstsecond quarter 2026 distributions.
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 threesix months ended MarchJune 31,30, 2026 were $49.4$117.7 million, a decrease of $4.8$8.8 million compared to $54.2$126.5 million for the threesix months ended MarchJune 31,30, 2025.
KRP insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 2 filings (1 insider, 2 trade dates, 6,224 shares, about $92.5K). Net open-market shares: -6,224 (purchases minus sales); net value about -$92.5K.Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-09-22 | Rhynsburger Blayne |
Open-market sale | 1,700 | $14.31 | $24.3K |
| 2026-08-25 | Rhynsburger Blayne |
Open-market sale | 4,524 | $15.08 | $68.2K |
Well-known investors holding KRP (13F)
None of the 59 investors we track reported a position in their latest 13F.