Kimbell Royalty Partners LP
For the period ended Dec 31, 2024. Filed Feb 27, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 27, 2025
KRP$15.15+0.8%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-02-21.
0001558370-24-001427
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-27.
0001558370-25-001800
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 161 previous paragraphs and 148 current paragraphs.
84 unchanged; 46 reworded; 9 added; 25 removed; 6 previous and 9 current paragraphs rearranged.
Tables are not compared: 13 previous and 13 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (9)
Current report
For the year ended December 31, 2024 lease bonus and other income was $6.0 million, an increase of $0.4 million compared to $5.6 million for the year ended December 31, 2023. The increase in lease bonus and other income is primarily due to a large number lease bonuses received during the year ended December 31, 2024.
Current report
Production and ad valorem taxes for the year ended December 31, 2024 remained flat at $20.4 million, compared to $20.3 million for the year ended December 31, 2023.
Current report
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas. As of December 31, 2024, the 12-month average prices of oil and natural gas were $75.48 per Bbl of oil and $2.13 per Mcf of natural gas. These prices represent a 3.5% and 19.3% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2023.
Current report
Cash flows used in investing activities for the year ended December 31, 2024 were $0.2 million compared to $246.7 million for the year ended December 31, 2023. For the year ended December 31, 2024, cash flows used in investing activities included the purchase of equipment.
Current report
Off-Balance Sheet Arrangements
Current report
As of December 31, 2024, we did not have any off-balance sheet arrangements.
Current report
We account for oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion in our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired mineral and royalty interests. As such, we consider the estimation of proved reserves to be a critical accounting estimate.
Current report
the total standardized measure of our reserves from December 31, 2023 to December 31, 2024, and were primarily related to technical revisions due to changes in commodity prices, historical and projected performance and other factors. Additionally, we continue to not intend to book PUD reserves.
Current report
Acquisitions of mineral and royalty interests were accounted for as asset acquisitions, whereby the purchase price and associated transaction costs are capitalized and allocated to the acquired mineral and royalty interests. The allocation is determined based on whether the interests acquired relate to proved or unproved oil and natural gas properties, utilizing the estimated fair value of proved reserves as of the date of acquisition. The valuation of proved reserves is based on a projection of future cash flows using objective future pricing assumptions and a discount rate consistent with our estimated cost of capital at the time of the acquisition. The remaining capitalized acquisition costs are allocated to the unproved properties acquired.
Removed paragraphs (25)
Previous report
On May 17, 2023, we completed the MB Minerals Acquisition. The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 OpCo common units and an equal number of Class B Units and (b) 557,302 common units. We funded the cash payment of the purchase price with borrowings under our secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas.
Previous report
Series A Preferred Units
Previous report
On August 2, 2023, we entered into a Series A preferred unit purchase agreement with the Series A Purchasers to issue and sell up to 400,000 Series A preferred units. On September 13, 2023, in connection with the closing of the LongPoint Acquisition, we completed the Preferred Unit Transaction. We used the net proceeds from the Preferred Unit Transaction to purchase 325,000 OpCo preferred units. The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition. The Series A preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation.
Previous report
Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions. We have the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum. If we make such an election in consecutive quarters or if we fail to pay in full, in cash and when due, any distribution owed to the Series A preferred units or otherwise materially breaches its obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid in full in cash, or any such material breach is cured, as applicable. Each holder of Series A preferred units has the right to share in any special distributions by us of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. We cannot declare or make any distributions, redemptions, or repurchases on any junior securities, including any of their common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.
Previous report
Beginning with the earlier of (i) the second anniversary of the original issuance date and (ii) immediately prior to our liquidation, the Series A Purchasers may, at any time (but not more often than once per quarter), elect to convert all or any portion of their Series A preferred units into a number of common units determined by multiplying the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that (a) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ remaining Series A preferred units and (b) the closing price of the common units is at least 130% of the conversion price of $15.07, subject to certain anti-dilution adjustments (the “Conversion Price”) for 20 trading days during the 30-trading day period immediately preceding the conversion notice.
Previous report
At any time on or after the second anniversary of the original issuance date, we will have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ Series A preferred units, (ii) the common units are listed for, or admitted to, trading on a national securities exchange, (iii) the closing price of the common units is at least 160% of the Conversion Price for 20 trading days during the 30-trading day period immediately preceding the conversion notice and (iv) we have an effective registration statement on file with the SEC covering resales of the underlying common units to be received by the holders of Series A preferred units upon such conversion.
Previous report
The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years. The Series A preferred units may be redeemed by us at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.
Previous report
For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the original issuance date, a 12.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the original issuance date and prior to the sixth anniversary of the original issuance date, a 13.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the original issuance date, a 14.0% internal rate of return with respect to the Series A preferred units.
Previous report
In connection with the issuance of the Series A preferred units, we granted holders of the Series A preferred units board observer rights beginning on the fifth anniversary of the original issuance date, board appointment rights beginning on the sixth anniversary of the original issuance date, and in the case of events of default with respect to the Series A preferred units, the right to appoint two members of the board beginning on the seventh anniversary of the original issuance date.
Previous report
The terms of the Series A preferred units contain covenants preventing us from taking certain actions without the approval of the holders of 662/3% of the outstanding Series A preferred units, voting separately as a class.
Previous report
As to us, $0.023897 of the OpCo common unit distribution corresponds to a tax payment made by us in the fourth quarter of 2023. 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 report
The 762 active rig count at December 31, 2022 increased significantly compared to 570 active land rigs at December 31, 2021. The increase in rig count for the 2022 period was primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices and overall supply shortages.
Previous report
Our lease bonus and other income remained relatively flat at $3.3 million for the year ended December 31, 2021, compared to December 31, 2022.
Previous report
For the year ended December 31, 2022, production and ad valorem taxes increased by $5.7 million from $10.5 million for the year ended December 31, 2021. The increase in production and ad valorem taxes was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2022, and to a lesser extent, production and ad valorem taxes associated with the Cornerstone Acquisition.
Previous report
Marketing and other deductions for the year ended December 31, 2022 increased by $1.4 million from $12.0 million for the year ended December 31, 2021. The increase in marketing and other deductions was primarily attributable the increase in prices for oil, natural gas and NGL production.
Previous report
Interest expense for the year ended December 31, 2022 increased by $4.6 million compared to interest expense of $9.2 million for the year ended December 31, 2021. The increase in interest expense was primarily due to debt incurred in the latter part of 2021 to fund the redemption of the Series A preferred units and the Cornerstone Acquisition and additional debt incurred in 2022 to fund the purchase of private placement warrants concurrently with the TGR IPO and to fund the cash purchase price paid in the Hatch Acquisition. Also contributing to the increase in interest expense was an increase in the weighted average interest rate from 3.86% at December 31, 2021 to 5.28% at December 31, 2022.
Previous report
Cash flows provided by operating activities for the year ended December 31, 2022 increased by $75.2 million compared to $91.4 million for the year ended December 31, 2021. The increase in cash flows provided by operating activities was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2022.
Previous report
Cash flows used in investing activities for the year ended December 31, 2022 increased by $319.1 million compared to cash flows used in used in investing activities of $55.6 million for the year ended December 31, 2021. For the year ended December 31, 2021, we used approximately $54.6 million to fund the Cornerstone acquisition, we used $0.8 million primarily to fund the renovation of office space, $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP, partially offset by a $0.5 million cash distribution received in connection with the Joint Venture during the period.
Previous report
We account for oil, natural gas and NGL producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil, natural gas and NGL properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil, natural gas and NGL properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Previous report
Depletion of evaluated oil, natural gas and NGL properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. Oil, natural gas and NGL reserve quantities are used as the basis to calculate unit-of-production depletion. Depletion is calculated by taking the ratio of asset costs to total proved reserves applied to actual production. The volumes produced and asset costs are known, while proved reserves are based on estimates that are subject to some variability.
Previous report
Unevaluated Properties
Previous report
Oil, Natural Gas and NGL Reserve Quantities
Previous report
There are numerous uncertainties inherent in estimating quantities of proved oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve engineering is a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and NGLs that are ultimately recovered. Additionally, we continue to not intend to book PUD reserves.
Previous report
Full Cost Ceiling Impairment
Previous report
The net capitalized costs of proved oil, natural gas and NGL properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. Estimated future net revenues are calculated as estimated future revenues from oil, natural gas and NGL properties less production taxes, ad valorem taxes and gas marketing expenses. To the extent capitalized costs of evaluated oil, natural gas and NGL properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil, natural gas and NGL reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil, natural gas and NGL prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the reporting period.
Reworded paragraphs (46)
Previous wording
This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Such views, beliefs, assumptions and estimates may, and often do, vary from actual results and the differences can be material. Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management.
Current wording
This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Such views, beliefs, assumptions and estimates may, and often do, vary from actual results and the differences can be material. Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this Annual Report.
Previous wording
On August 7, 2023, we completed an underwritten public offering of 8,337,500 common units for net proceeds of approximately $110.7 million (the “2023 Equity Offering”). We used the net proceeds from the 2023 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $90.0 million of the outstanding borrowings under our secured revolving credit facility. The Operating Company used the remainder of the net proceeds of the 2023 Equity Offering for general corporate purposes.
Current wording
On January 9, 2025, we completed an underwritten public offering of 11,500,000 common units for net proceeds of approximately $163.6 million (the “2025 Equity Offering”). We used the net proceeds from the 2025 Equity Offering to purchase OpCo common units. The Operating Company ultimately used the net proceeds of the 2025 Equity Offering to fund the Boren Acquisition (as defined below).
Previous wording
On September 13, 2023, we completed the LongPoint Acquisition in a cash transaction valued at approximately $455.0 million. We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the Preferred Unit Transaction.
Current wording
On January 17, 2025, we completed the Boren Acquisition in a cash transaction valued at approximately $230.4 million. We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the 2025 Equity Offering. Theoil and gas properties acquired are located under the Mabee Ranch in the Midland Basin in Texas. As of December 31, 2024, the acquired assets would have added 0.86 DUCs and net permitted locations on our acreage (0.64 net DUCs and 0.22 net permitted locations) and daily production of 1,864 Boe/d.
Previous wording
On February 21, 2024, the Board of Directors declared a quarterly cash distribution of $0.43 per common unit and $0.453897 per OpCo common units for the quarter ended December 31, 2023. We intend to pay the distributions on March 20, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on March 13, 2024.
Current wording
On February 27, 2025, the Board of Directors declared a quarterly cash distribution of $0.40 per common unit and OpCo common unit for the quarter ended December 31, 2024. We intend to pay the distributions on March 25, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on March 18, 2025.
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 and is still active. 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 January 2025, Israel and Hamas agreed to a ceasefire deal, however, 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.
Previous wording
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from various OPEC announcements, the winter storms experienced in parts of the United States in February 2021 and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”).
Current wording
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from various OPEC announcements and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”).
Previous wording
On February 5, 2024, the WTI posted price for crude oil was $73.21 per Bbl and the Henry Hub spot market price of natural gas was $2.12 per MMBtu.
Current wording
On February 10, 2025, the WTI posted price for crude oil was $72.73 per Bbl and the Henry Hub spot market price of natural gas was $3.48 per MMBtu.
Previous wording
The Baker Hughes United States Rotary Rig count decreased 21% to 602 active land rigs at December 31, 2023 compared to 762 active land rigs at December 31, 2022. The overall decrease in rig count December 31, 2023 compared December 31, 2022 is primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.
Current wording
The 602 active rig count at December 31, 2023 decreased 21% compared to 762 active land rigs at December 31, 2022. The overall decrease in rig count at December 31, 2023 compared December 31, 2022 is primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.
Previous wording
The tables below identify our proved reserves at December 31, 2023, 2022 and 2021, in each case based on the reserve report prepared by Ryder Scott. The prices used to estimate proved reserves for the respective periods were held
Current wording
The tables below identify our proved reserves at December 31, 2024, 2023 and 2022, in each case based on the reserve report prepared by Ryder Scott. The prices used to estimate proved reserves for the respective periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
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 years ended December 31, 2023, 2022 and 2021 include the MB Minerals Acquisition, the Longpoint Acquisition, the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”)and the acquisition of all of the equity interests incertain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”).
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 years ended December 31, 2024, 2023 and 2022 include the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”), the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) and the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”).
Previous wording
We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.
Current wording
We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate
Previous wording
We recorded an impairment on our oil and natural gas properties of $18.2 million during the year ended December 31, 2023. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the years ended December 31, 2022 and 2021.
Current wording
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural. As of December 31, 2024, the 12-month average prices of oil and natural gas were $75.48 per Bbl of oil and $2.13 per Mcf of natural gas. These prices represent a 3.5% and 19.3% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2023. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2022.
Previous wording
Our revenues for the year ended December 31, 2022 increased by $106.9 million, from $175.1 million for the year ended December 31, 2021. The significant increase in oil, natural gas and NGL revenues was primarily related to the increase in the average prices we received for oil, natural gas and NGL production, and to a lesser extent, an increase in production volumes for the year ended December 31, 2022 as discussed below.
Current wording
For the year ended December 31, 2024, our oil, natural gas and NGL revenues were $304.6 million, an increase of $37.0 million from $267.6 million for the year ended December 31, 2023. The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the year ended December 31, 2024 as discussed below.
Previous wording
For the year ended December 31, 2023, our oil, natural gas and NGL revenues were $267.6 million, a decrease of $14.4 million from $282.0 million for the year ended December 31, 2022. The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the year ended December 31, 2023 as discussed below.
Current wording
Our revenues for the year ended December 31, 2023 decreased by $14.4 million, from $282.0 million for the year ended December 31, 2022. The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the year ended December 31, 2023 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 7,372,622 Boe or 20,265 Boe/d, for the year ended December 31, 2023, an increase of 1,814,750 Boe or 5,240 Boe/d, from 5,557,872 Boe or 15,025 Boe/d, for the year ended December 31, 2022. The increase in production for the year ended December 31, 2023 was primarily attributable to production associated with the Hatch Acquisition, which included a full year of production for the year ended December 31, 2023, compared to approximately three months of production for the year ended December 31, 2022, the MB Minerals Acquisition, and to a lesser extent, production associated with the LongPoint 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 9,101,745 Boe or 24,868 Boe/d, for the year ended December 31, 2024, an increase of 1,729,123 Boe or 4,603 Boe/d, from 7,372,622 Boe or 20,265 Boe/d, for the year ended December 31, 2023. The increase in production for the year ended December 31, 2024 was primarily attributable to production associated with the MB Minerals Acquisition and the LongPoint Acquisition, which included a full year of production for the year ended December 31, 2024, compared to a partial year of production for the year ended December 31, 2023.
Previous wording
Our production volumes for the year ended December 31, 2022 increased by 318,707 Boe or 671 Boe/d, from 5,239,165 Boe or 14,354 Boe/d, for the year ended December 31, 2021. The increase in production for the year ended December 31, 2022 was primarily attributable to production associated with the Cornerstone Acquisition, which included a full year of production for the year ended December 31, 2022, compared to approximately three months of production for the year ended December 31, 2021, and to a lesser extent, production associated with the Hatch Acquisition.
Current wording
Our production volumes for the year ended December 31, 2023 increased by 1,814,750 Boe or 5,240 Boe/d, from 5,557,872 Boe or 15,025, for the year ended December 31, 2022. The increase in production for the year ended December 31, 2023 was primarily attributable to production associated with the Hatch Acquisition, which included a full year of production for the year ended December 31, 2023, compared to approximately three months of production for the year ended December 31, 2022, the MB Minerals Acquisition, and to a lesser extent, production associated with the LongPoint Acquisition.
Previous wording
Our operators received an average of $76.55 per Bbl of oil, $2.55 per Mcf of natural gas and $23.01 per Bbl of NGL for the volumes sold during the year ended December 31, 2023 and $91.74 per Bbl of oil, $6.04 per Mcf of natural gas and $38.19 per Bbl of NGL for the volumes sold during the year ended December 31, 2022. The year ended December 31, 2023 decreased 16.6% or $15.19 per Bbl of oil and 57.8% or $3.49 per Mcf of natural gas compared to the year ended December 31, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 18.3% or $17.32 per Bbl of oil and 60.8% or $3.92 per Mcf of natural gas for the comparable periods.
Current wording
Our operators received an average of $75.98 per Bbl of oil, $1.82 per Mcf of natural gas and $23.34 per Bbl of NGL for the volumes sold during the year ended December 31, 2024 and $76.55 per Bbl of oil, $2.55 per Mcf of natural gas and $23.01 per Bbl of NGL for the volumes sold during the year ended December 31, 2023. The year ended December 31, 2024 decreased 0.7% or $0.57 per Bbl of oil and 28.6% or $0.73 per Mcf of natural gas compared to the year ended December 31, 2023. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 1.2% or $0.95 per Bbl of oil and 13.4% or $0.34 per Mcf of natural gas for the comparable periods.
Previous wording
Average prices received by our operators during the year ended December 31, 2022 increased 41.4% or $26.88 per Bbl of oil and 72.1% or $2.53 per Mcf of natural gas compared to the year ended December 31, 2021, which our operators received an average of $64.86 per Bbl of oil, $3.51 per Mcf of natural gas and $29.33 per Bbl of NGL. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 39.3% or $26.76 per Bbl of oil and 65.8% or $2.56 per Mcf of natural gas for the comparable periods.
Current wording
Average prices received by our operators during the year ended December 31, 2023 decreased 16.6% or $15.19 per Bbl of oil and 57.8% or $3.49 per Mcf of natural gas compared to the year ended December 31, 2022, which our operators received an average of $91.74 per Bbl of oil, $6.04 per Mcf of natural gas and $38.19 per Bbl of NGL. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 18.3% or $17.32 per Bbl of oil and 60.8% or $3.92 per Mcf of natural gas for the comparable periods.
Previous wording
For the year ended December 31, 2023 lease bonus and other income was $5.6 million, an increase of $2.5 million compared to $3.1 million for the year ended December 31, 2022. The increase in lease bonus and other income is primarily related to legal settlements received during the year ended December 31, 2023.
Current wording
Our lease bonus and other income for the year ended December 31, 2023 increased by $2.5 million compared to $3.1 million for the year ended December 31, 2022. The increase in lease bonus and other income is primarily related to legal settlements received during the year ended December 31, 2023.
Previous wording
Gain on commodity derivative instruments for the year ended December 31, 2023 included $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments compared to $16.0 million of mark-to-market gains and $53.0 million of losses on the settlement of commodity derivative instruments for the year ended December 31, 2022. We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was partially offset by the realized losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2022 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the losses on the settlement of commodity derivative instruments.
Current wording
Loss on commodity derivative instruments for the year ended December 31, 2024 included $12.2 million of mark-to-market losses and $10.9 million of gains on the settlement of commodity derivative instruments compared to $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments for the year ended December 31, 2023. We recorded a mark-to-market loss for the year ended December 31, 2024 as a result of the increase in oil and natural gas strip pricing from the year ended December 31, 2023, offset by realized gains on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was partially offset by the realized losses on the settlement of commodity derivative instruments.
Previous wording
Production and ad valorem taxes for the year ended December 31, 2023 were $20.3 million, an increase of $4.1 million from $16.2 million for the year ended December 31, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition. The increase was partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.
Current wording
For the year ended December 31, 2023, production and ad valorem taxes increased by $4.1 million from $16.2 million for the year ended December 31, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition. The increase was partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.
Previous wording
Depreciation and depletion expense for the year ended December 31, 2023 was $96.5 million, an increase of $46.4 million from $50.1 million for the year ended December 31, 2022. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
Current wording
Depreciation and depletion expense for the year ended December 31, 2024 was $135.1 million, an increase of $38.6 million from $96.5 million for the year ended December 31, 2023. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
Previous wording
For the year ended December 31, 2022, depreciation and depletion expense increased by $13.3 million from $36.8 million for the year ended December 31, 2021. The increase in depreciation and depletion expense was due to the Cornerstone Acquisition and the Hatch Acquisition, which significantly increased our net capitalized oil and natural gas properties.
Current wording
For the year ended December 31, 2023, depreciation and depletion expense increased by $46.4 million from $50.1 million for the year ended December 31, 2022. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly 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 unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $13.03 for the year ended December 31, 2023, an increase of $4.19 per barrel from the $8.84 average depletion rate per barrel for the year ended December 31, 2022. The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
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 unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $14.80 for the year ended December 31, 2024, an increase of $1.77 per barrel from the $13.03 average depletion rate per barrel for the year ended December 31, 2023. The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
Previous wording
For the year ended December 31, 2022, our average depletion rate per barrel increased by $2.06 per barrel from the $6.78 average depletion rate per barrel for the year ended December 31, 2021. The increase in our average depletion rate per barrel was due to the Cornerstone Acquisition and the Hatch Acquisition, which collectively increased our net capitalized oil and natural gas properties.
Current wording
For the year ended December 31, 2023, our average depletion rate per barrel increased by $4.19 per barrel from the $8.84 average depletion rate per barrel for the year ended December 31, 2022. The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
Previous wording
We recorded an impairment on our oil and natural gas properties of $18.2 million during the year ended December 31, 2023. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the years ended December 31, 2022 and 2021.
Current wording
As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2022.
Previous wording
Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the year ended December 31, 2023 were $12.6 million, a decrease of $0.8 million from $13.4 million for the year ended December 31, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition.
Current wording
Marketing and other deductions for the year ended December 31, 2023 decreased by $0.8 million from $13.4 million for the year ended December 31, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition.
Previous wording
General and administrative expenses for the year ended December 31, 2023 were $35.7 million, an increase of $6.6 million from $29.1 million for the year ended December 31, 2022. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was attributable to a $2.0 million increase in unit-based compensation expense, expenses related to a one-time cash bonus paid to employees and cash general and administrative expenses resulting from an increase in our costs associated with company growth.
Current wording
General and administrative expenses for the year ended December 31, 2024 were $38.5 million, an increase of $2.8 million from $35.7 million for the year ended December 31, 2023. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was attributable to a $3.3 million increase in unit-based compensation expense, partially offset by a $0.4 million decrease in cash expenses.
Previous wording
General and administrative expenses for the year ended December 31, 2022 increased by $2.1 million from $27.0 million for the year ended December 31, 2021. The increase in general and administrative expenses was primarily attributable to legal and professional fees incurred related to thespecial meeting of unitholders of the Partnership in May 2022, at which our unitholders approved the adoption of our Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan and our Amended and Restated Agreement of Limited Partnership, and cash general and administrative expenses resulting from an increase in our costs associated with company growth.
Current wording
General and administrative expenses for the year ended December 31, 2023 increased by $6.6 million from $29.1 million for the year ended December 31, 2022. The increase in general and administrative expenses was attributable to a $2.0 million increase in unit-based compensation expense, expenses related to a one-time cash bonus paid to employees and cash general and administrative expenses resulting from an increase in our costs associated with company growth.
Previous wording
Interest expense for the year ended December 31, 2023 was $26.0 million as compared to interest expense of $13.8 million for the year ended December 31, 2022. The increase in interest expense was primarily due to an increase in the weighted average interest rate on our outstanding borrowings from 5.28% at December 31, 2022 to 8.62% at December 31, 2023. Also contributing to the increase in interest expense was an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint Acquisition.
Current wording
Interest expense for the year ended December 31, 2023 increased by $12.2 million compared to interest expense of $13.8 million for the year ended December 31, 2022. The increase in interest expense was primarily due to an increase in the weighted average interest rate on our outstanding borrowings from 5.28% at December 31, 2022 to 8.62% at December 31, 2023. Also contributing to the increase in interest expense was an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint Acquisition.
Previous wording
For the year ended December 31, 2023, we recognized an income tax expense of $3.8 million, resulting in an effective tax rate of 4.34%, compared to income tax expense of $2.7 million for the year ended December 31, 2022, resulting in an effective tax rate of 2.05%. We recognized an income tax expense of $0.1 million for the year ended December 31, 2021, resulting in an effective tax rate of 0.17%. The overall change in our effective tax rate for the year ended December 31, 2023 is primarily due estimated current federal and state income tax that cannot be sheltered by a net operating loss carryforward.
Current wording
For the year ended December 31, 2024, we recognized an income tax benefit of $0.8 million, resulting in an effective tax benefit of 7.49%, compared to income tax expense of $3.8 million for the year ended December 31, 2023, resulting in an effective tax rate of 4.34%. We recognized an income tax expense of $2.7 million for the year ended December 31, 2022, resulting in an effective tax rate of 2.05%.
Previous wording
Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral
Current wording
Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. On June 13, 2023, we entered into the A&R Credit Agreement (as
Previous wording
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
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.
Previous wording
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2023 for the repayment of $13.8 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2023. 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 fourth quarter of 2024 for the repayment of $14.3 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2024. 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
Operating cash flow is impacted by many variables, the most significant of which are the changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs we receive from our operators on those volumes. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2023 were $174.3 million, an increase of $7.7 million compared to $166.6 million for the year ended December 31, 2022.
Current wording
Operating cash flow is impacted by many variables, the most significant of which are the changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs we receive from our operators on those volumes. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2024 were $250.9 million, an increase of $76.6 million compared to $174.3 million for the year ended December 31, 2023.
Previous wording
Cash flows used in investing activities for the year ended December 31, 2023 were $246.7 million compared to $374.7 million for the year ended December 31, 2022. For the year ended December 31, 2023, cash flows used in investing activities included $490.7 million used to fund costs associated with the MB Minerals Acquisition and the LongPoint Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $243.2 million of cash received from investment held in trust related to TGR and $0.9 million in cash received from the dissolution of TGR.
Current wording
For the year ended December 31, 2023, cash flows used in investing activities included $490.7 million used to fund costs associated with the MB Minerals Acquisition and the LongPoint Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $243.2 million of cash received from investment held in trust related to Kimbell Tiger Acquisition Corporation (“TGR”) and $0.9 million in cash received from the dissolution of TGR.
Previous wording
Cash flows used in financing activities for the year ended December 31, 2021 consists of $71.7 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $67.1 million to fund the redemption of Series A preferred units, $91.0 million used to repay borrowings under our secured revolving credit facility, $2.1 million of restricted units repurchased for tax withholding, $0.7 million payment of loan origination costs and $0.2 million paid in connection with the redemption of Class B units, partially offset by $57.5 million in proceeds from the 2021 equity offering and $136.6 million of additional borrowings under our secured revolving credit facility.
Current wording
Cash flows used in financing activities were $247.5 million for the year ended December 31, 2024 compared to $78.4 million of cash flows provided by financing activities for the year ended December 31, 2023. Cash flows used in financing activities for the year ended December 31, 2024 consists primarily of $187.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $60.0 million used to repay borrowings under our secured revolving credit facility, $4.9 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
Cash flows provided by financing activities were $78.4 million for the year ended December 31, 2023 compared to $226.1 million of cash flows provided by financing activities for the year ended December 31, 2022. Cash flows provided by financing activities for the year ended December 31, 2023 consists of $314.0 million in net proceeds from the issuance of Series A preferred units, $201.1 million of additional borrowings under our secured revolving credit facility, $110.7 million in proceeds from the 2023 Equity Offering, and $0.3 million in Class B contributions, partially offset by$243.2 million of distributions to common unitholders of TGR, $153.0 million of distributions paid to holders of common
Current wording
Cash flows provided by financing activities for the year ended December 31, 2023 consists of $314.0 million in net proceeds from the issuance of Series A preferred units, $201.1 million of additional borrowings under our secured revolving credit facility, $110.7 million in proceeds from the 2023 Equity Offering, and $0.3 million in Class B
Previous wording
units, OpCo common units, Series A preferred units and Class B units, $139.9 million used to repay borrowings under our secured revolving credit facility, $4.9 millionof restricted units repurchased for tax withholding and a $6.7 million payment of loan origination costs.
Current wording
contributions, partially offset by$243.2 million of distributions to common unitholders of TGR, $153.0 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $139.9 million used to repay borrowings under our secured revolving credit facility, $4.9 millionof restricted units repurchased for tax withholding and a $6.7 million payment of loan origination costs.
Previous wording
Cash flows provided by financing activities for the year ended December 31, 2022 consists of $227.6 million in proceeds from the TGR IPO (these proceeds were held in trust for the benefit of public stockholders and not available to KRP), $199.2 million of additional borrowings under our secured revolving credit facility, $116.1 million in proceeds from the 2022 equity offering and $0.4 million in contributions from Class B unitholders, partially offset by $183.3 million used to repay borrowings under our secured revolving credit facility, $126.8 million of distributions paid to holders of common units, OpCo common units and Class B units, $3.3 millionof restricted units repurchased for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units and $0.7 million payment of loan origination costs.
Current wording
Cash flows provided by financing activities for the year ended December 31, 2022 consists of $227.6 million in proceeds from the TGR initial public offering (these proceeds were held in trust for the benefit of public stockholders and not available to KRP), $199.2 million of additional borrowings under our secured revolving credit facility, $116.1 million in proceeds from the 2022 equity offering and $0.4 million in contributions from Class B unitholders, partially offset by $183.3 million used to repay borrowings under our secured revolving credit facility, $126.8 million of distributions paid to holders of common units, OpCo common units and Class B units, $3.3 millionof restricted units repurchased for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units and $0.7 million payment of loan origination costs.
Showing the first 40 of 46 pairs. Open the source sections for the rest.
Rearranged current paragraphs (9)
Current report — wording carried from elsewhere
The Baker Hughes United States Rotary Rig count decreased 4.8% to 573 active land rigs at December 31, 2024 compared to 602 active land rigs at December 31, 2023. While the United States Rotary Rig count decreased year over year, overall production is not decreasing, indicating improved efficiencies are allowing sustained production from fewer rigs.
Current report — wording carried from elsewhere
results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.
Current report — wording carried from elsewhere
(Loss) Gain on Commodity Derivative Instruments
Current report — wording carried from elsewhere
Loss on commodity derivative instruments for the year ended December 31, 2022 included $16.0 million of mark-to-market gains and $53.0 million of losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2022 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the losses on the settlement of commodity derivative instruments.
Current report — wording carried from elsewhere
Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the year ended December 31, 2024 were $16.1 million, an increase of $3.5 million from $12.6 million for the year ended December 31, 2023. The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the MB Minerals Acquisition and the LongPoint Acquisition, which included a full year of marketing and other deductions for the year ended December 31, 2024, compared to a partial year of marketing and other deductions for the year ended December 31, 2023.
Current report — wording carried from elsewhere
Interest expense for the year ended December 31, 2024 was $26.7 million as compared to interest expense of $26.0 million for the year ended December 31, 2023. The increase in interest expense was attributable to an increase in the overall long-term debt balance as a result of borrowings associated with the MB Minerals Acquisition and the LongPoint Acquisition in May 2023 and September 2023, respectively. This increase was partially offset by a decrease in the weighted average interest rate on our outstanding borrowings from 8.62% at December 31, 2023 to 8.42% at December 31, 2024, coupled with the repayment of $60.0 million on our secured revolving credit facility for the year ended December 31, 2024.
Current report — wording carried from elsewhere
Cash flows provided by operating activities for the year ended December 31, 2023 increased by $7.7 million compared to $166.6 million for the year ended December 31, 2022.
Current report — wording carried from elsewhere
Oil, Natural Gas and NGL Reserves
Current report — wording carried from elsewhere
Acquisitions of Mineral and Royalty Interests
Rearranged previous paragraphs (6)
Previous report — wording carried elsewhere
We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this Annual Report.
Previous report — wording carried elsewhere
constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
Previous report — wording carried elsewhere
Gain (Loss) on Commodity Derivative Instruments
Previous report — wording carried elsewhere
Loss on commodity derivative instruments for the year ended December 31, 2021 included $22.1 million of mark-to-market losses and $20.7 million of losses on the settlement of commodity derivative instruments.
Previous report — wording carried elsewhere
Method of Accounting for Oil and Natural Gas Properties
Previous report — wording carried elsewhere
Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves, which is primarily based upon when such properties become producing. We assess all items classified as unevaluated property on a periodic basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes