Kimbell Royalty Partners, LP

Previous 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.

Current 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.

Previous 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.

Current 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.

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

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 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.

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. 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.

Current wording

The recent U.S. military action in Iran has led to regional instability and caused dramatic fluctuations in global financial markets and increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, we have not experienced a material adverse impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us.

Previous 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.

Current 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.

Previous 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.

Current 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.

Previous 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.

Current 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.

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

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 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 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.

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

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,

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, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.

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 months ended March 31, 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 six months ended June 30, 2026 and 2025.

Previous 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.

Current 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.

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 2,296,970 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.

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 2,350,521 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.

Previous 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.

Current 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.

Previous 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.

Current 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.

Previous 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.

Current 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.

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 $12.74 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.

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 $12.84 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.

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 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.

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 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.

Previous 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.

Current 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.

Previous 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.

Current 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.

Previous 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

Current 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.

Previous 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.

Current 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.

Previous 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.

Current 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.

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 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.

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 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.

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 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.

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

Previous 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.

Current 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.

Previous 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.

Current 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.

Previous 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.

Current 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.

Previous 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.

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. In connection with the May 1, 2026 redetermination, the borrowing base and aggregate elected commitments increased from $625.0 million to $660.0 million.

Previous wording

Distributions in excess of the amount taxable as dividend income will reduce a common unitholder’s tax basis in its common units or produce capital gain to the extent they exceed a common unitholder’s tax basis. Any reduced tax basis will increase a common unitholder’s capital gain when it sells its common units. Our estimates are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax “earnings and profits.” Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter.

Current wording

will increase a common unitholder’s capital gain when it sells its common units. Our estimates are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax “earnings and profits.” Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter.