Kimbell Royalty Partners, LP

Previous wording

As of September 30, 2025, we owned mineral and royalty interests in approximately 12.3 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 55% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of September 30, 2025, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 131,000 gross wells, including over 52,000 wells in the Permian Basin.

Current wording

As of March 31, 2026, we owned mineral and royalty interests in approximately 12.3 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of March 31, 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 133,000 gross wells, including over 53,000 wells in the Permian Basin.

Previous wording

On November 6, 2025, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.35 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 September 30, 2025. We intend to pay the distributions on November 24, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on November 17, 2025.

Current wording

On May 7, 2026, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.41 per common unit representing limited partner interests in the Partnership (“common unit”) and common unit of the Operating Company (“OpCo common unit”) for the quarter ended March 31, 2026. We intend to pay the distributions on May 27, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on May 19, 2026.

Previous wording

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 $2.5 million for the quarter ended

Current wording

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

Previous wording

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. In October 2025, Israel and Hamas agreed to a ceasefire deal, although there is no assurance that the ceasefire will continue. 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.

Current wording

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 the recent U.S. military action in Venezuela and Iran, 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.

Previous wording

On October 27, 2025, the West Texas Intermediate posted price for crude oil was $62.13 per Bbl and the Henry Hub spot market price of natural gas was $3.30 per MMBtu.

Current wording

On April 27, 2026, the West Texas Intermediate posted price for crude oil was $99.89 per Bbl and the Henry Hub spot market price of natural gas was $2.72 per MMBtu.

Previous wording

The Baker Hughes United States Rotary Rig count decreased by 6.2% to 532 active land rigs at September 30, 2025 compared to 567 active land rigs at September 30, 2024. The 532 active land rigs at September 30, 2025 decreased slightly compared to 533 active land rigs at June 30, 2025. 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.

Current wording

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.

Previous wording

We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non-cash unit based compensation and unrealized gains and losses on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

Current wording

We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non-cash unit based compensation and unrealized gains and losses on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units as Adjusted EBITDA, less cash needed for debt service and other

Previous wording

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

Current wording

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three months ended March 31, 2026 and 2025 include the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in January 2025.

Previous wording

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.

Current wording

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,

Previous wording

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.

Current wording

Accounting standards require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience significant downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 2026 and 2025.

Previous wording

For the three months ended September 30, 2025, our oil, natural gas and NGL revenues were $76.8 million, an increase of $5.7 million from $71.1 million for the three months ended September 30, 2024. The increase in oil, natural gas and NGL revenues was primarily related to revenues associated with the Boren Acquisition and also an increase in the average prices received for natural gas coupled with an increase in production volumes for the three months ended September 30, 2025, partially offset by a decrease in the average prices received for oil and NGLs, as discussed below.

Current wording

For the three months ended March 31, 2026, our oil, natural gas and NGL revenues were $82.9 million, a decrease of $7.1 million from $90.0 million for the three months ended March 31, 2025. The decrease 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 oil coupled with a slight increase in production volumes for the three months ended March 31, 2026, as discussed below.

Previous wording

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 2,348,775 Boe or 25,530 Boe/d, for the three months ended September 30, 2025, an increase of 154,899 Boe or 1,684 Boe/d, from 2,193,876 Boe or 23,846 Boe/d, for the three months ended September 30, 2024. The increase in production volumes for the three months ended September 30, 2025 was primarily attributable to production associated with the Boren Acquisition.

Current wording

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 2,296,970 Boe or 25,522 Boe/d, for the three months ended March 31, 2026, an increase of 1,880 Boe or 21 Boe/d, from 2,295,090 Boe or 25,501 Boe/d, for the three months ended March 31, 2025.

Previous wording

Our operators received an average of $64.42 per Bbl of oil, $2.67 per Mcf of natural gas and $21.36 per Bbl of NGL for the volumes sold during the three months ended September 30, 2025 compared to $78.09 per Bbl of oil, $1.60 per Mcf of natural gas and $21.49 per Bbl of NGL for the volumes sold during the three months ended September 30, 2024. These average prices received during the three months ended September 30, 2025 decreased 17.5% or $13.67 per Bbl of oil and increased 66.9% or $1.07 per Mcf of natural gas as compared to the three months ended September 30, 2024. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 13.9% or $10.65 per Bbl of oil and an increase of 43.6% or $0.92 per Mcf of natural gas for the comparable periods.

Current wording

Our operators received an average of $69.55 per Bbl of oil, $3.15 per Mcf of natural gas and $23.93 per Bbl of NGL for the volumes sold during the three months ended March 31, 2026 compared to $69.27 per Bbl of oil, $3.87 per Mcf of natural gas and $27.99 per Bbl of NGL for the volumes sold during the three months ended March 31, 2025. The average price received during the three months ended March 31, 2026 increased 0.4% or $0.28 per Bbl of oil, which is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 1.3% or $0.96 per Bbl of oil. The average price received during the three months ended March 31, 2026 decreased 18.6% or

Previous wording

Lease bonus and other income for the three months ended September 30, 2025 was $0.4 million, a decrease of $2.8 million compared to $3.2 million for the three months ended September 30, 2024. The decrease in lease bonus and other income was due to a large lease bonus received during the three months ended September 30, 2024.

Current wording

Lease bonus and other income for the three months ended March 31, 2026 was $1.3 million, an increase of $1.0 million compared to $0.3 million for the three months ended March 31, 2025. The increase in lease bonus and other income was due to a large number of lease bonuses received during the three months ended March 31, 2026.

Previous wording

Gain on commodity derivative instruments for the three months ended September 30, 2025 included $1.8 million of mark-to-market gains and $1.6 million of gains on the settlement of commodity derivative instruments compared to $7.1 million of mark-to-market gains and $2.5 million of gains on the settlement of commodity derivative instruments for the three months ended September 30, 2024. We recorded a mark-to-market gains for both the three months ended September 30, 2025 and 2024 as a result of the maturity of derivative contracts with lower strike pricing.

Current wording

Loss on commodity derivative instruments for the three months ended March 31, 2026 included $18.8 million of mark-to-market losses and $0.1 million of gains on the settlement of commodity derivative instruments compared to $7.0 million of mark-to-market losses and $0.9 million of gains on the settlement of commodity derivative instruments for the three months ended March 31, 2025. We recorded mark-to-market losses for the both the three months ended March 31, 2026 and 2025 as a result of an increase in strip pricing from the previous quarter, partially offset by gains on the settlement of commodity derivative instruments.

Previous wording

Production and ad valorem taxes for the three months ended September 30, 2025 were $5.6 million, an increase of $1.3 million compared to $4.3 million for the three months ended September 30, 2024. 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 natural gas, partially offset by a decrease in the average prices received for oil and NGLs for the three months ended September 30, 2025.

Current wording

Production and ad valorem taxes for the three months ended March 31, 2026 were $5.9 million, an increase of $0.5 million compared to $5.4 million for the three months ended March 31, 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 NGLs for the three months ended March 31, 2026.

Previous wording

Depreciation and depletion expense for the three months ended September 30, 2025 was $31.0 million, a decrease of $1.2 million from $32.2 million for the three months ended September 30, 2024. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.

Current wording

Depreciation and depletion expense for the three months ended March 31, 2026 was $29.3 million, a decrease of $1.8 million from $31.1 million for the three months ended March 31, 2025. The decrease in depreciation and depletion expense was due to the gradual reduction in the depletable base of our oil and natural gas properties.

Previous wording

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $13.19 for the three months ended September 30, 2025, a decrease of $1.42 per barrel from the $14.61 average depletion rate per barrel for the three months ended September 30, 2024. The decrease in the depletion rate was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.

Current wording

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 for the three months ended March 31, 2026, a decrease of $0.78 per barrel from the $13.52 average depletion rate per barrel for the three months ended March 31, 2025. The decrease in the depletion rate was due to the gradual reduction in the depletable base of our oil and natural gas properties.

Previous wording

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended September 30, 2025 were $5.1 million, an increase of $1.5 million compared to $3.6 million for the three months ended September 30, 2024. 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 natural gas, partially offset by a decrease in the average prices received for oil and NGLs for the three months ended September 30, 2025.

Current wording

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended March 31, 2026 were $5.2 million, an increase of $0.7 million compared to $4.5 million for the three months ended March 31, 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 NGLs for the three months ended March 31, 2026.

Previous wording

General and administrative expenses for the three months ended September 30, 2025 were $10.1 million, an increase of $0.6 million compared to $9.5 million for the three months ended September 30, 2024. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to an increase in unit-based compensation expense and an increase in cash general and administrative expenses resulting from an increase in our costs associated with company growth.

Current wording

General and administrative expenses for the three months ended March 31, 2026 were $9.4 million, a decrease of $0.2 million compared to $9.6 million for the three months ended March 31, 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 decrease in general and administrative expenses was primarily attributable to an overall decrease in cash general and administrative expenses, partially offset by an increase in unit-based compensation expense.

Previous wording

Interest expense for the three months ended September 30, 2025 was $9.8 million, compared to $6.5 million for the three months ended September 30, 2024. 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 partial redemption of the Series A preferred units.

Current wording

Interest expense for the three months ended March 31, 2026 was $8.2 million, compared to $6.6 million for the three months ended March 31, 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 partial redemption of the Series A preferred units.

Previous wording

We recorded an income tax benefit of $3.3 million and an expense of $1.9 million for the three months ended September 30, 2025 and 2024, respectively.

Current wording

We recorded an income tax expense of $0.7 million and $1.1 million for the three months ended March 31, 2026 and 2025, respectively.

Previous wording

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. On May 1, 2025, in connection with the redetermination, the Partnership entered into Amendment No. 3 (as defined below) to the A&R Credit Agreement that, among other things, increase each of the borrowing base and aggregate elected commitments from $550.0 million to $625.0 million. See “Indebtedness” below for further discussion of our secured revolving credit facility.

Current wording

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 December 16, 2025, we entered into a Second Amended and Restated Credit Agreement (the “Second A&R Credit Agreement”). See “Indebtedness” below for further discussion of our secured revolving credit facility.

Previous wording

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.

Current wording

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, cash used for repurchases of our common units under the Repurchase Program 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, cash used for repurchases of our common units under the Repurchase Program, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

Previous wording

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the third quarter of 2025 for the repayment of $12.6 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the third quarter of 2025. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future.

Current wording

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the first quarter of 2026 for the repayment of $14.5 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the first 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.

Previous wording

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we completed the Boren Acquisition partially with net proceeds from the 2025 Equity Offering. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our third quarter 2025 distributions.

Current wording

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we completed the Boren Acquisition partially with net proceeds from anunderwritten 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 first quarter 2026 distributions.

Previous wording

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 nine months ended September 30, 2025 were $189.2 million, a decrease of $5.1 million compared to $194.3 million for the nine months ended September 30, 2024.

Current wording

Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the three months ended March 31, 2026 were $49.4 million, a decrease of $4.8 million compared to $54.2 million for the three months ended March 31, 2025.

Previous wording

Cash flows used in investing activities for the nine months ended September 30, 2025 were $223.4 million compared to $0.2 million for the nine months ended September 30, 2024. For the nine months ended September 30, 2025, cash flows used in investing activities primarily related to the Boren Acquisition. For the nine months ended September 30, 2024, cash flows used in investing activities included the purchase of equipment.

Current wording

Cash flows used in investing activities for the three months ended March 31, 2026 were $0.01 million compared to $222.9 million for the three months ended March 31, 2025. For the three months ended March 31, 2026, cash flows used in investing activities primarily related the purchase of office equipment. For the three months ended March 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition.

Previous wording

Cash flows provided by financing activities were $40.0 million for the nine months ended September 30, 2025 compared to $190.5 million of cash flows used in financing activities for the nine months ended September 30, 2024. Cash flows provided by financing activities for the nine months ended September 30, 2025 consists primarily of$163.6 million in proceeds from the 2025 Equity Offering and$254.1 million of additional borrowings under our secured revolving credit facility, partially offset by $179.9 million used to redeem a portion of the Series A preferred units,$147.0 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $44.8 million used to repay borrowings under our secured revolving credit facility and $5.1 millionof restricted units repurchased for tax withholding.

Current wording

Cash flows used in financing activities were $56.2 million for the three months ended March 31, 2026 compared to $170.3 million of cash flows provided by financing activities for the three months ended March 31, 2025. Cash flows used in financing activities for the three months ended March 31, 2026 consists primarily of $42.6 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $13.4 million used to repay borrowings under our secured revolving credit facility, $7.3 million used to repurchase common units and $5.2 millionof restricted units repurchased for tax withholding, partially offset by$12.8 million of additional borrowings under our secured revolving credit facility.

Previous wording

Cash flows used in financing activities for the nine months ended September 30, 2024 consists primarily of $143.1 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $47.0 million used to repay borrowings under our secured revolving credit facility, $4.9 millionof 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.

Current wording

Cash flows provided by financing activities for the three months ended March 31, 2025 consists primarily of$163.6 million in proceeds from the 2025 Equity Offering and$74.1 million of additional borrowings under our secured revolving credit facility, partially offset by$48.1 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $14.3 million used to repay borrowings under our secured revolving credit facility and $5.1 millionof restricted units repurchased for tax withholding.

Previous wording

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.

Current wording

On December 16, 2025, we entered into a Second A&R Credit Agreement, which amended and restated our existing Amended and Restated Credit Agreement, dated as of June 13, 2023 (as amended on July 24, 2023, December 8, 2023, and May 1, 2025). 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 $1.5 billion with an initial borrowing base of $625.0 million and an initial aggregate elected commitments amount of up to $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 December 16, 2030.

Previous wording

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.

Current wording

For additional information on our Second A&R Credit Agreement, please read Note 9―Long-Term Debt to the unaudited interim consolidated financial statements included in this Quarterly Report.

Previous wording

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 2025. 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.

Current wording

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 is held by the OpCo common unitholders, is 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 2026. 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.