Kimbell Royalty Partners, LP

Previous wording

As of June 30, 2026, we owned mineral and royalty interests in approximately 12.5 million gross acres and overriding royalty interests in approximately 4.8 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 June 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 134,000 gross wells, including over 54,000 wells in the Permian Basin.

Current wording

As of September 30, 2026, we owned mineral and royalty interests in approximately 12.8 million gross acres and overriding royalty interests in approximately 4.8 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 September 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 137,000 gross wells, including over 54,000 wells in the Permian Basin.

Previous wording

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.

Current wording

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 common units of the Operating Company (“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.

Previous wording

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.

Current wording

We and our subsidiaries acquired (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, a Texas general partnership, and RCPTX, Ltd., a Texas limited partnership, that were not already owned by us. The aggregate consideration for the Dropdown consisted of approximately $74.9 million in cash and the issuance of 9,500,000 OpCo common units and an equal number of Class B units. The Partnership funded the cash consideration of the purchase price with borrowings under its secured revolving credit facility.

Previous wording

On August 7, 2026, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.47 per common unit representing limited partner interests in the Partnership (“common unit”) and $0.496665 per common unit of the Operating Company (“OpCo common unit”) for the quarter ended June 30, 2026. We intend to pay the distributions on August 24, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on August 17, 2026.

Current wording

On November 5, 2026, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.45 per common unit representing limited partner interests in the Partnership (“common unit”) and $0.463091 per OpCo common unit for the quarter ended September 30, 2026. We intend to pay the distributions on November 23, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on November 16, 2026.

Previous wording

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.

Current wording

As to us, $0.013091 of the OpCo common unit distribution corresponds to a tax payment made by us in the third 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.

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 $2.4 million for the quarter ended June 30, 2026. We intend to pay the distribution subsequent to August 7, 2026 and prior to the distribution on the common units and OpCo common units.

Current wording

We will pay a cash distribution on the Series A preferred units of approximately $2.5 million for the quarter ended September 30, 2026. We intend to pay the distribution subsequent to November 5, 2026 and prior to the distribution on the common units and OpCo common units.

Previous wording

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 June 30, 2026 resulted in a reduction to current income tax expense, primarily due to the changes to the 163(j) interest limitation.

Current wording

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 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 resulted in a reduction to income tax expense, primarily due to the changes to the 163(j) interest limitation.

Previous wording

On July 27, 2026, the West Texas Intermediate posted price for crude oil was $84.25 per Bbl and the Henry Hub spot market price of natural gas was $2.63 per MMBtu.

Current wording

On October 27, 2026, the West Texas Intermediate posted price for crude oil was $103.37 per Bbl and the Henry Hub spot market price of natural gas was $2.76 per MMBtu.

Previous wording

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.

Current wording

The Baker Hughes United States Rotary Rig count increased by 10.2% to 586 active land rigs at September 30, 2026 compared to 532 active land rigs at September 30, 2025. The 586 active land rigs at September 30, 2026 increased by 4.5% compared to 561 active land rigs at June 30, 2026. The increase in rig count is primarily related to the energy crisis in the Middle East and surging global oil prices.

Previous wording

analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution on common units are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

Current wording

Adjusted EBITDA and cash available for distribution on common units are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution on common units are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

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

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.

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 effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of

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 and nine months ended September 30, 2026 and 2025 include the Dropdown in August 2026, the

Previous wording

our results for the three and six months ended June 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.

Current wording

Mesa Acquisition in June 2026 and the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in January 2025.

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. We did not record an impairment on our oil and natural gas properties for the three and six months ended June 30, 2026 and 2025.

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 and nine months ended September 30, 2026 and 2025.

Previous wording

For the three months ended June 30, 2026, our oil, natural gas and NGL revenues were $103.0 million, an increase of $28.3 million from $74.7 million for the three 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 three months ended June 30, 2026, as discussed below.

Current wording

For the three months ended September 30, 2026, our oil, natural gas and NGL revenues were $96.9 million, an increase of $20.1 million from $76.8 million for the three months ended September 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 an increase in production volumes for the three months ended September 30, 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 2,350,521 Boe or 25,830 Boe/d, for the three months ended June 30, 2026, an increase of 43,237 Boe or 475 Boe/d, from 2,307,284 Boe or 25,355 Boe/d, for the three months ended June 30, 2025.

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 2,535,964 Boe or 27,565 Boe/d, for the three months ended September 30, 2026, an increase of 187,189 Boe or 2,035 Boe/d, from 2,348,775 Boe or 25,530 Boe/d, for the three months ended September 30, 2025. The increase in production volumes is primarily related to production associated with the Mesa Acquisition and the Dropdown.

Previous wording

Lease bonus and other income for the three months ended June 30, 2026 was $3.3 million, an increase of $0.8 million compared to $2.5 million for the three months ended June 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 June 30, 2026.

Current wording

Lease bonus and other income for the three months ended September 30, 2026 was $2.6 million, an increase of $2.2 million compared to $0.4 million for the three months ended September 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 September 30, 2026.

Previous wording

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.

Current wording

Loss on commodity derivative instruments for the three months ended September 30, 2026 included $11.8 million of mark-to-market losses and $1.3 million of losses on the settlement of commodity derivative instruments compared to $1.8 million of mark-to-market gains and $1.6 million of gains on the settlement of commodity derivative instruments for the three months ended September 30, 2025. We recorded a mark-to-market loss for the three months ended September 30, 2026 as a result of an increase in strip pricing from the previous quarter. We recorded a mark-to-market gain for the three months ended September 30, 2025 as a result of the maturity of derivative contracts with lower strike pricing.

Previous wording

Production and ad valorem taxes for the three months ended June 30, 2026 were $8.2 million, an increase of $2.5 million compared to $5.7 million for the three 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 three months ended June 30, 2026, and to a lesser extent, the slight increase in production volumes.

Current wording

Production and ad valorem taxes for the three months ended September 30, 2026 were $7.5 million, an increase of $1.9 million compared to $5.6 million for the three months ended September 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 three months ended September 30, 2026, and an increase in production volumes primarily related to the Mesa Acquisition and the Dropdown.

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 $12.84 for the three months ended June 30, 2026, a decrease of $0.32 per barrel from the $13.16 average depletion rate per barrel for the three 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.

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 $12.96 for the three months ended September 30, 2026, a decrease of $0.23 per barrel from the $13.19 average depletion rate per barrel for the three months ended September 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 and the Dropdown, which increased our net capitalized 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 June 30, 2026 were $4.2 million, an increase of $1.2 million compared to $3.0 million for the three 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 three months ended June 30, 2026, and to a lesser extent, the slight increase in production volumes.

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 September 30, 2026 were $4.0 million, a decrease of $1.1 million compared to $5.1 million for the three months ended September 30, 2025. The decrease in marketing and other deductions was primarily related to the volatility in pricing along with the timing of marketing and other deduction costs, partially offset by costs associated with the Mesa Acquisition and the Dropdown.

Previous wording

General and administrative expenses for the three months ended June 30, 2026 were $10.2 million, an increase of $0.6 million compared to $9.6 million for the three 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 overall increase in cash general and administrative expenses and a $0.2 million increase in unit-based compensation expense.

Current wording

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 overall increase in cash general and administrative expenses and a $0.2 million increase in unit-based compensation expense.

Previous wording

We recorded an income tax expense of $4.0 million and $2.2 million for the three months ended June 30, 2026 and 2025, respectively.

Current wording

We recorded an income tax expense of $4.4 million and a benefit of $3.3 million for the three months ended September 30, 2026 and 2025, respectively. On July 4, 2025, the Act was enacted by the U.S. government. We recognized the effects of the new tax law in the period of enactment, which resulted in a reduction to income tax expense, primarily due to the changes to the 163(j) interest limitation.

Previous wording

Comparison of the Six Months Ended June 30, 2026 to the Six Months Ended June 30, 2025

Current wording

Comparison of the Nine months Ended September 30, 2026 to the Nine months Ended September 30, 2025

Previous wording

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.

Current wording

For the nine months ended September 30, 2026, our oil, natural gas and NGL revenues were $282.8 million, an increase of $41.3 million from $241.5 million for the nine months ended September 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 an increase in production volumes for the nine months ended September 30, 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 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.

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 7,183,455 Boe or 26,313 Boe/d, for the nine months ended September 30, 2026, an increase of 232,306 Boe or 851 Boe/d, from 6,951,149 Boe or 25,462 Boe/d, for the nine months ended September 30, 2025. The increase in production volumes is primarily related to production associated with the Mesa Acquisition and the Dropdown.

Previous wording

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.

Current wording

Our operators received an average of $84.02 per Bbl of oil, $2.34 per Mcf of natural gas and $24.96 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2026 compared to $65.71 per Bbl of oil, $2.96 per Mcf of natural gas and $24.23 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2025. The average price received during the nine months ended September 30, 2026 increased 27.9% or $18.31 per Bbl of oil, which is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 26.7% or $17.94 per Bbl of oil. The average price received during the nine months ended September 30, 2026 decreased 20.9% or $0.62 per Mcf of natural gas as compared to the nine months ended September 30, 2025 as a result of lower differentials in the Permian Basin.

Previous wording

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.

Current wording

Lease bonus and other income for the nine months ended September 30, 2026 was $7.3 million, an increase of $4.1 million compared to $3.2 million for the nine months ended September 30, 2025. The increase in lease bonus and other income was due to an increase in activity during the nine months ended September 30, 2026.

Previous wording

Gain on commodity derivative instruments for the three months ended June 30, 2026 included $9.3 million of mark-to-market gains and $3.2 million of losses on the settlement of commodity derivative instruments compared to $8.5 million of mark-to-market gains and $0.8 million of gains on the settlement of commodity derivative instruments for the three months ended June 30, 2025. We recorded a mark-to-market gain for the three months ended June 30, 2026 and 2025 as a result of the maturity of derivative contracts with lower strike pricing.

Current wording

Loss on commodity derivative instruments for the nine months ended September 30, 2026 included $21.3 million of mark-to-market losses and $4.4 million of losses on the settlement of commodity derivative instruments compared to $3.3 million of mark-to-market gains and $3.4 million of gains on the settlement of commodity derivative instruments for the nine months ended September 30, 2025. We recorded a mark-to-market loss for the nine months ended September 30, 2026 as a result of an increase in strip pricing from the previous quarter. We recorded a mark-to-market gain for the nine months ended September 30, 2025 as a result of the maturity of derivative contracts with lower strike pricing.

Previous wording

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.

Current wording

Production and ad valorem taxes for the nine months ended September 30, 2026 were $21.6 million, an increase of $4.9 million from $16.7 million for the nine months ended September 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 nine months ended September 30, 2026, and an increase in production volumes primarily related to the Mesa Acquisition and the Dropdown.

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 $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.

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 $12.85 for the nine months ended September 30, 2026, a decrease of $0.44 per barrel from the $13.29 average depletion rate per barrel for the nine months ended September 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 and the Dropdown, which increased our net capitalized 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 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.

Current wording

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the nine months ended September 30, 2026 was $13.3 million, an increase of $0.7 million compared to $12.6 million for the nine months ended September 30, 2025. The increase in marketing and other deductions was primarily related to the increase in the average prices received for oil for the nine months ended September 30, 2026, and an increase in production volumes primarily related to the Mesa Acquisition and the Dropdown.

Previous wording

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.

Current wording

General and administrative expenses for the nine months ended September 30, 2026 were $30.3 million, an increase of $1.0 million compared to $29.3 million for the nine months ended September 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.

Previous wording

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.

Current wording

Interest expense for the nine months ended September 30, 2026 was $26.2 million, compared to $25.4 million for the nine months ended September 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 Mesa Acquisition and the Dropdown.

Previous wording

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the second quarter of 2026 for the repayment of $17.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the second 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.

Current wording

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the third quarter of 2026 for the repayment of $18.8 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the third 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 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 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 second quarter 2026 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 issued 9,500,000 OpCo common units and an equal number of Class B units as partial consideration in connection with the Dropdown, 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 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 third 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

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 nine months ended September 30, 2026 were $175.9 million, a decrease of $13.3 million compared to $189.2 million for the nine months ended September 30, 2025.

Previous wording

Cash flows used in investing activities for the six months ended June 30, 2026 were $44.4 million compared to $223.3 million for the six months ended June 30, 2025. For the six months ended June 30, 2026, cash flows used in investing activities primarily related to the Mesa Acquisition. For the six months ended June 30, 2025, cash flows used in investing activities primarily related to the Boren Acquisition.

Current wording

Cash flows used in investing activities for the nine months ended September 30, 2026 were $114.1 million compared to $223.4 million for the nine months ended September 30, 2025. For the nine months ended September 30, 2026, cash flows used in investing activities primarily related to the Mesa Acquisition and the Dropdown. For the nine months ended September 30, 2025, cash flows used in investing activities primarily related to the Boren Acquisition.

Previous wording

Cash flows used in financing activities were $72.4 million for the six months ended June 30, 2026 compared to $97.2 million of cash flows provided by financing activities for the six months ended June 30, 2025. Cash flows used in financing activities for the six months ended June 30, 2026 consists primarily of $89.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $27.9 million used to repay borrowings under our secured revolving credit facility, $14.7 million used to repurchase common units and $5.2 millionof restricted units repurchased for tax withholding, partially offset by$65.1 million of additional borrowings under our secured revolving credit facility.

Current wording

Cash flows used in financing activities were $72.0 million for the nine months ended September 30, 2026 compared to $40.0 million of cash flows provided by financing activities for the nine months ended September 30, 2025. Cash flows used in financing activities for the nine months ended September 30, 2026 consists primarily of $145.9 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $45.8 million used to repay borrowings under our secured revolving credit facility, $14.7 million used to repurchase common units and $5.2 millionof restricted units repurchased for tax withholding, partially offset by$140.1 million of additional borrowings under our secured revolving credit facility.

Previous wording

Cash flows provided by financing activities for the six months ended June 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,$103.6 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $31.2 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 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.