Kimbell Royalty Partners, LP

Previous wording

On May 8, 2025, 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 common unit of the Operating Company (“OpCo common unit”) for the quarter ended March 31, 2025. We intend to pay the distributions on May 28, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on May 20, 2025.

Current wording

On August 7, 2025, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.38 per common unit representing limited partner interests in the Partnership (“common unit”) and $0.380261 per common unit of the Operating Company (“OpCo common unit”) for the quarter ended June 30, 2025. We intend to pay the distributions on August 25, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on August 18, 2025.

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 $4.8 million for the quarter ended March 31, 2025. We intend to pay the distribution subsequent to May 8, 2025 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 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, 2025. We intend to pay the distribution subsequent to August 7, 2025 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. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. In January 2025, Israel and Hamas agreed to a ceasefire deal, however, in March 2025 Israel carried out air strikes against Hamas, suggesting there is no indication on the extent of the ceasefire. 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. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. In January 2025, Israel and Hamas agreed to a ceasefire deal, however, the ceasefire has not held and the conflict has continued. 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.

Previous wording

President Trump has executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of commodities, increase the price of supplies and raw materials that we rely on, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our operations and expenses.

Current wording

and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of commodities, increase the price of supplies and raw materials that we rely on, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our operations and expenses.

Previous wording

On April 28, 2025, the West Texas Intermediate posted price for crude oil was $63.30 per Bbl and the Henry Hub spot market price of natural gas was $2.96 per MMBtu.

Current wording

On July 28, 2025, the West Texas Intermediate posted price for crude oil was $67.81 per Bbl and the Henry Hub spot market price of natural gas was $3.12 per MMBtu.

Previous wording

The Baker Hughes United States Rotary Rig count decreased by 4.3% to 575 active land rigs at March 31, 2025 compared to 601 active land rigs at March 31, 2024. The 575 active land rigs at March 31, 2025 increased slightly compared to 573 active land rigs at December 31, 2024. While the United States Rotary Rig count decreased year over year, overall production is not decreasing, indicating improved efficiencies are allowing sustained production from fewer rigs.

Current wording

The Baker Hughes United States Rotary Rig count decreased by 4.8% to 533 active land rigs at June 30, 2025 compared to 560 active land rigs at June 30, 2024. The 533 active land rigs at June 30, 2025 decreased by 7.3% compared to 575 active land rigs at March 31, 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.

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 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, 2025 and 2024 include 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

Previous wording

We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 2025. As a result of our full cost ceiling analysis, we recorded an impairment on our oil and natural gas properties of $6.0 million during the three months ended March 31, 2024. The impairment was primarily attributed to the decline in the 12-month average price of oil and natural gas for the three months ended March 31, 2024. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas.

Current wording

We did not record an impairment on our oil and natural gas properties for the three and six months ended June 30, 2025 or the three months ended June 30, 2024. As a result of our full cost ceiling analysis, we recorded an impairment on our oil and natural gas properties of $6.0 million during the six months ended June 30, 2024. The impairment was primarily attributed to the decline in the 12-month average price of oil and natural gas for the three months ended March 31, 2024.

Previous wording

For the three months ended March 31, 2025, our oil, natural gas and NGL revenues were $90.0 million, an increase of $2.5 million from $87.5 million for the three months ended March 31, 2024. The increase in oil, natural gas and NGL revenues was primarily related to an increase in the average prices received for natural gas and NGLs for the three months ended March 31, 2025 as discussed below.

Current wording

For the three months ended June 30, 2025, our oil, natural gas and NGL revenues were $74.7 million, a decrease of $2.3 million from $77.0 million for the three months ended June 30, 2024. The decrease in oil, natural gas and NGL revenues was primarily related to decrease in the average prices received for oil and NGLs, partially offset by an increase in the average prices received for natural gas and an increase in production volumes for the three months ended June 30, 2025 as discussed below.

Previous wording

Our operators received an average of $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 compared to $76.60 per Bbl of oil, $1.96 per Mcf of natural gas and $24.70 per Bbl of NGL for the volumes sold during the three months ended March 31, 2024. These average prices received during the three months ended March 31, 2025 decreased 9.6% or $7.33 per Bbl of oil and increased 97.4% or $1.91 per Mcf of natural gas as compared to the three months ended March 31, 2024. This change is

Current wording

Our operators received an average of $63.52 per Bbl of oil, $2.34 per Mcf of natural gas and $23.56 per Bbl of NGL for the volumes sold during the three months ended June 30, 2025 compared to $77.20 per Bbl of oil, $2.10 per Mcf of natural gas and $24.75 per Bbl of NGL for the volumes sold during the three months ended June 30, 2024. These average prices received during the three months ended June 30, 2025 decreased 17.7% or $13.68 per Bbl of oil and increased 11.4% or $0.24 per Mcf of natural gas as compared to the three months ended June 30, 2024. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 21.1% or $17.24 per Bbl of oil and an increase of 54.1% or $1.12 per Mcf of natural gas for the comparable periods.

Previous wording

Loss on Commodity Derivative Instruments

Current wording

Gain (Loss) on Commodity Derivative Instruments

Previous wording

Loss on commodity derivative instruments for the three months ended March 31, 2025 included $7.0 million of mark-to-market losses and $0.9 million of gains on the settlement of commodity derivative instruments compared to $8.7 million of mark-to-market losses and $3.0 million of gains on the settlement of commodity derivative instruments for the three months ended March 31, 2024. We recorded a mark-to-market losses for the three months ended March 31, 2025 and 2024 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, 2025 included $8.5 million of mark-to-market gains and $0.8 million of gains on the settlement of commodity derivative instruments compared to $3.8 million of mark-to-market losses and $2.8 million of gains on the settlement of commodity derivative instruments for the three months ended June 30, 2024. We recorded a mark-to-market gain for the three months ended June 30, 2025 as a result of the maturity of derivative contracts with lower strike pricing. We recorded a mark-to-market loss for the three months ended June 30, 2024 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

Lease bonus and other income for the three months ended March 31, 2025 remained relatively flat at $0.3 million, compared to $0.4 million for the three months ended March 31, 2024.

Current wording

Production and ad valorem taxes for the three months ended June 30, 2025 remained relatively flat at $5.7 million, compared to $5.6 million for the three months ended June 30, 2024.

Previous wording

Depreciation and depletion expense for the three months ended March 31, 2025 was $31.1 million, a decrease of $7.1 million from $38.2 million for the three months ended March 31, 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 June 30, 2025 was $30.5 million, a decrease of $2.5 million from $33.0 million for the three months ended June 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.

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 $13.52 for the three months ended March 31, 2025, a decrease of $1.72 per barrel from the $15.24 average depletion rate per barrel for the three months ended March 31, 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 $13.16 for the three months ended June 30, 2025, a decrease of $1.85 per barrel from the $15.01 average depletion rate per barrel for the three months ended June 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.

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, 2025 remained relatively flat at $4.5 million, compared to $4.6 million for the three months ended March 31, 2024.

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, 2025 were $3.0 million, a decrease of $0.8 million compared to $3.8 million for the three months ended June 30, 2024. The decrease in marketing and other deductions was primarily related to decrease in the average prices received for oil and NGLs, partially offset by an increase in the average prices received for natural gas for the three months ended June 30, 2025.

Previous wording

General and administrative expenses for the three months ended March 31, 2025 were $9.6 million, an increase of $0.2 million compared to $9.4 million for the three months ended March 31, 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.

Current wording

General and administrative expenses for the three months ended June 30, 2025 were $9.6 million, a decrease of $0.7 million compared to $10.3 million for the three months ended June 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 decrease in general and administrative expenses was primarily attributable to a decrease in unit-based compensation expense.

Previous wording

Interest expense for the three months ended March 31, 2025 was $6.6 million, compared to $7.3 million for the three months ended March 31, 2024. The decrease in interest expense was primarily due to a 1.03% decrease in the weighted average interest rate on our outstanding borrowings for the three months ended March 31, 2025.

Current wording

Interest expense for the three months ended June 30, 2025 was $8.9 million, compared to $6.9 million for the three months ended June 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.

Previous wording

We recorded an income tax expense of $1.1 million and $0.9 million for the three months ended March 31, 2025 and 2024, respectively.

Current wording

We recorded an income tax expense of $2.2 million and $1.8 million for the three months ended June 30, 2025 and 2024, respectively.

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 2,295,090 Boe or 25,501 Boe/d, for the three months ended March 31, 2025, a decrease of 203,258 Boe or 1,953 Boe/d, from 2,498,348 Boe or 27,454 Boe/d, for the three months ended March 31, 2024. The decrease in production for the three months ended March 31, 2025 was primarily attributable to 252,653 Boe or 2,776 Boe/d of prior period production recognized for the three months ended March 31, 2024, partially offset by 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 4,602,374 Boe or 25,427 Boe/d, for the six months ended June 30, 2025, a decrease of 89,938 Boe or 355 Boe/d, from 4,692,312 Boe or 25,782 Boe/d, for the six months ended June 30, 2024. The decrease in production for the six months ended June 30, 2025 was primarily attributable to prior period production recognized for the six months ended June 30, 2024, partially offset by production associated with the Boren Acquisition.

Previous wording

Production and ad valorem taxes for the three months ended March 31, 2025 were $5.4 million, a decrease of $1.1 million from $6.5 million for the three months ended March 31, 2024. The decrease in production and ad valorem taxes was primarily attributable to the decrease in oil and natural gas production, partially offset by an increase in production and ad valorem taxes associated with the Boren Acquisition.

Current wording

Production and ad valorem taxes for the six months ended June 30, 2025 were $11.1 million, a decrease of $1.0 million from $12.1 million for the six months ended June 30, 2024. The decrease in production and ad valorem taxes was primarily attributable to the decrease in oil and natural gas production, partially offset by an increase in production and ad valorem taxes associated with the Boren Acquisition.

Previous wording

We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 2025. We recorded an impairment on our oil and natural gas properties of $6.0 million during the three months ended March 31, 2024, as a result of our full cost ceiling analysis. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas.

Current wording

We did not record an impairment on our oil and natural gas properties for the six months ended June 30, 2025. We recorded an impairment on our oil and natural gas properties of $6.0 million during the six months ended June 30, 2024, as a result of our full cost ceiling analysis. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas.

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. 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 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 recent 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.

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 2025 for the repayment of $16.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the first 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 second quarter of 2025 for the repayment of $13.6 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the second quarter of 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.

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 first 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 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 2025 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, 2025 were $54.2 million, a decrease of $14.8 million compared to $69.0 million for the three months ended March 31, 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 six months ended June 30, 2025 were $126.5 million, a decrease of $5.4 million compared to $131.9 million for the six months ended June 30, 2024.

Previous wording

Cash flows used in investing activities for the three months ended March 31, 2025 were $222.9 million compared to $0.1 million for the three months ended March 31, 2024. For the three months ended March 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition. For the three months ended March 31, 2024, cash flows used in investing activities included costs associated with an acquisition and the purchase of equipment.

Current wording

Cash flows used in investing activities for the six months ended June 30, 2025 were $223.3 million compared to $0.1 million for the six months ended June 30, 2024. For the six months ended June 30, 2025, cash flows used in investing activities primarily related to the Boren Acquisition. For the six months ended June 30, 2024, cash flows used in investing activities included the purchase of equipment.

Previous wording

Cash flows provided by financing activities were $170.3 million for the three months ended March 31, 2025 compared to $60.3 million of cash flows used in financing activities for the three months ended March 31, 2024. 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 were $97.2 million for the six months ended June 30, 2025 compared to $131.8 million of cash flows used in financing activities for the six months ended June 30, 2024. 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

Cash flows used in financing activities for the three months ended March 31, 2024 consists primarily of $46.5 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $13.8 million used to repay borrowings under our secured revolving credit facility and $4.9 millionof restricted units repurchased for tax withholding, partially offset by$5.0 million of additional borrowings under our secured revolving credit facility.

Current wording

Cash flows used in financing activities for the six months ended June 30, 2024 consists primarily of $98.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $33.4 million used to repay borrowings under our secured revolving credit facility, $4.9 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.

Previous wording

For additional information on our secured revolving credit facility, please read Note 9―Long-Term Debt and Note 17―Subsequent Events to the unaudited interim consolidated financial statements included in this Quarterly Report.

Current 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.