# Kimbell Royalty Partners, LP: Form 10-Q for the period ended Mar 31, 2025

- Company: [Kimbell Royalty Partners, LP](/companies/krp.md) (CIK 1657788)
- Form: 10-Q
- Filed: 2025-05-08
- Accepted by EDGAR: May 8, 2025, 20:05 ET
- Period: 2025-03-31
- Accession: 0001558370-25-006965
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1657788/000155837025006965/krp-20250331x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1657788/000155837025006965/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-01-01 to 2025-03-31 | $84.2m | us-gaap:Revenues |
| Selling, general and administrative | 3 months, 2025-01-01 to 2025-03-31 | $9.6m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2025-01-01 to 2025-03-31 | $33.6m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-01-01 to 2025-03-31 | $6.6m | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2025-01-01 to 2025-03-31 | $1.1m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-01-01 to 2025-03-31 | $25.9m | us-gaap:ProfitLoss |
| Operating cash flow | 3 months, 2025-01-01 to 2025-03-31 | $54.2m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2025-03-31 | $35.6m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-03-31 | $99.4m | us-gaap:AssetsCurrent |
| Total assets | at 2025-03-31 | $1.33bn | us-gaap:Assets |
| Current liabilities | at 2025-03-31 | $16.5m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-03-31 | $322.2m | us-gaap:Liabilities |

## Management's discussion and analysis

As filed, 52,459 characters.

*The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited interim consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024 (the “2024 Form 10-K”).*

*Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “our Partnership,” “we” “our,” or “us” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to our subsidiary Kimbell Royalty Operating, LLC. References to “our General Partner” refer to Kimbell Royalty GP, LLC. References to “our Sponsors” refer to affiliates of our founders, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of our Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to us.*

### Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this Quarterly Report may constitute forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

- our ability to replace our reserves;
- our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions;
- our ability to execute our business strategies;
- the volatility of realized prices for oil, natural gas and natural gas liquids (“NGLs”), including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries;
- the level of production on our properties;
- the level of drilling and completion activity by the operators of our properties;
- our ability to forecast identified drilling locations, gross horizontal wells, drilling inventory and estimates of reserves on our properties and on properties we seek to acquire;
- regional supply and demand factors, delays or interruptions of production;
- industry, economic, business or political conditions, including the energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies;
- trade policies and tensions, including changes in, or the imposition of, tariffs and/or trade barriers and the economic impacts, volatility and uncertainty resulting therefrom, which may have varying effects on commodity prices;
- the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine and the conflict in the Middle East;
- revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;
- impact of impairment expense on our financial statements;
- competition in the oil and natural gas industry generally and the mineral and royalty industry in particular;
- the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;
- title defects in the properties in which we acquire an interest;
- the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel to the operators of our properties;
- restrictions on or the availability of the use of water in the business of the operators of our properties;
- the availability of transportation facilities;
- the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
- federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry, including regulation, proposals, and executive orders focused on addressing climate change;
- future operating results;
- exploration and development drilling prospects, inventories, projects and programs;
- operating hazards faced by the operators of our properties;
- the ability of the operators of our properties to keep pace with technological advancements;
- uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions; and
- our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures.

These factors are discussed in further detail in the 2024 Form 10-K under “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II and elsewhere in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

### Overview

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. We have elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of March 31, 2025, we owned mineral and royalty interests in approximately 12.3 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 55% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of March 31, 2025, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 131,000 gross wells, including over 52,000 wells in the Permian Basin.

The following table summarizes our ownership in United States basins and producing regions and information about the wells in which we have a mineral or royalty interest as March 31, 2025:

| ​ ​ ​ Basin or Producing Region | ​ ​ ​ ​ | ​ ​ ​ Gross Acreage | ​ ​ ​ ​ | ​ ​ ​ Net Acreage | ​ ​ ​ ​ | ​ Average Daily Production (Boe/d)(6:1)(1) | ​ ​ ​ ​ | ​ ​ ​ Well Count |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Permian Basin | ​ | 3,404,777 | ​ | 27,799 | ​ | 10,831 | ​ | 52,162 |
| Mid‑Continent |  | 5,868,926 | ​ | 48,832 | ​ | 4,577 | ​ | 21,029 |
| Terryville/Cotton Valley/Haynesville |  | 1,428,907 | ​ | 7,919 | ​ | 3,918 | ​ | 16,372 |
| Appalachian Basin | ​ | 741,354 | ​ | 23,203 | ​ | 1,590 | ​ | 3,965 |
| Bakken/Williston Basin |  | 1,640,077 | ​ | 6,138 | ​ | 849 | ​ | 5,519 |
| Eagle Ford |  | 624,148 | ​ | 6,730 | ​ | 1,774 | ​ | 4,448 |
| DJ Basin/Rockies/Niobrara |  | 74,152 | ​ | 1,036 | ​ | 775 | ​ | 12,598 |
| Other |  | 3,232,560 | ​ | 36,693 | ​ | 1,187 | ​ | 15,478 |
| Total |  | 17,014,901 | ​ | 158,350 | ​ | 25,501 | ​ | 131,571 |

(1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our 2024 Form 10-K.

The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of March 31, 2025:

| ​ Basin or Producing Region(1) | ​ ​ | ​ Gross DUCs | ​ ​ | ​ Gross Permits | ​ ​ | ​ Net DUCs | ​ ​ | ​ Net Permits |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Permian Basin | ​ | 503 | ​ | 491 | ​ | 2.64 | ​ | 2.55 |
| Mid‑Continent |  | 114 | ​ | 78 | ​ | 0.91 | ​ | 0.41 |
| Terryville/Cotton Valley/Haynesville |  | 40 | ​ | 22 | ​ | 0.37 | ​ | 0.16 |
| Appalachian Basin | ​ | 2 | ​ | 1 | ​ | 0.02 | ​ | — |
| Bakken/Williston Basin |  | 70 | ​ | 67 | ​ | 0.31 | ​ | 0.22 |
| Eagle Ford |  | 67 | ​ | 22 | ​ | 0.32 | ​ | 0.08 |
| DJ Basin/Rockies/Niobrara |  | 12 | ​ | 1 | ​ | 0.10 | ​ | 0.01 |
| Total |  | 808 | ​ | 682 | ​ | 4.67 | ​ | 3.43 |

(1) The above table represents DUCs and permitted locations only, and there is no guarantee that the DUCs or permitted locations will be developed into producing wells in the future.

### Recent Developments

#### Equity Offering

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).

#### Acquisitions

On January 17, 2025, we completed the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in a transaction valued at approximately $230.4 million, including transaction costs and certain customary post-closing adjustments. We funded the cash consideration of the purchase price with borrowings under our secured revolving credit facility and net proceeds from the 2025 Equity Offering. The oil and gas properties acquired are located under the Mabee Ranch in the Midland Basin in Texas.

#### Quarterly Distributions

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.

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.

### Business Environment

### Global Conflicts and Uncertainties

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.

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.

### Commodity Prices and Demand

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 by the United States Energy Information Administration (the “EIA”).

| ​ ​ ​ | ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 High | ​ | ​ ​ Low | ​ ​ ​ | ​ ​ Three Months Ended March 31, 2024 High | ​ | ​ ​ Low |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Oil ($/Bbl) | ​ | $80.73 | ​ | $66.31 | ​ | $84.39 | ​ | $70.62 |
| Natural gas ($/MMBtu) | ​ | $9.86 | ​ | $2.93 | ​ | $13.20 | ​ | $1.25 |

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.

The following table, as reported by the EIA, sets forth the average daily prices for oil and natural gas.

| ​ ​ ​ | ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 | ​ | ​ ​ 2024 | ​ ​ ​ |
| --- | --- | ---: | --- | ---: | --- |
| Oil ($/Bbl) | ​ | $71.78 | ​ | $77.50 | ​ |
| Natural gas ($/MMBtu) | ​ | $4.14 | ​ | $2.15 | ​ |

### Rig Count

Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

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.

The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated:

| ​ ​ Basin or Producing Region | ​ ​ ​ | ​ March 31, 2025 | ​ ​ | ​ 2024 |
| --- | --- | ---: | --- | ---: |
| Permian Basin | ​ | 49 | ​ | 50 |
| Mid‑Continent | ​ | 19 | ​ | 23 |
| Terryville/Cotton Valley/Haynesville | ​ | 6 | ​ | 9 |
| Bakken/Williston Basin | ​ | 8 | ​ | 6 |
| Eagle Ford | ​ | 5 | ​ | 8 |
| DJ Basin/Rockies/Niobrara | ​ | 1 | ​ | 1 |
| Other | ​ | 2 | ​ | 1 |
| Total | ​ | 90 | ​ | 98 |

### Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices received.

The following table presents the breakdown of our oil, natural gas and NGL revenues for the following periods:

| ​ ​ ​ Revenue | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 ​ ​ | ​ ​ | ​ ​ 2024 ​ ​ |
| --- | --- | ---: | --- | ---: |
| Oil revenue | ​ | 58% | ​ | 70% |
| Natural gas revenue | ​ | 29% | ​ | 17% |
| NGL revenue | ​ | 13% | ​ | 13% |
| ​ | ​ | 100% | ​ | 100% |

We have entered into oil and natural gas commodity derivative agreements, which extend through March 2027, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests. For further discussion on our commodity derivative agreements, see “Note 5—Derivatives.”

### Non-GAAP Financial Measures

### Adjusted EBITDA and Cash Available for Distribution on Common Units

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

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.

Adjusted EBITDA and cash available for distribution on common units should not be considered an alternative to net income (loss), oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA and cash available for distribution on common units may not be comparable to other similarly titled measures of other companies.

The tables below present a reconciliation of Adjusted EBITDA and cash available for distribution on common units to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated (unaudited).

| ​ ​ ​ Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 ​ ​ | ​ ​ ​ | ​ ​ 2024 ​ ​ |
| --- | --- | --- | --- | --- |
| Net income | ​ | $25,853,195 | ​ | $9,336,939 |
| Depreciation and depletion expense | ​ | ​ 31,118,095 | ​ | ​ 38,166,806 |
| Interest expense | ​ | ​ 6,621,526 | ​ | ​ 7,301,330 |
| Income tax expense | ​ | ​ 1,089,426 | ​ | ​ 922,568 |
| EBITDA | ​ | ​ 64,682,242 | ​ | ​ 55,727,643 |
| Impairment of oil and natural gas properties | ​ | ​ — | ​ | ​ 5,963,575 |
| Unit-based compensation | ​ | ​ 3,861,815 | ​ | ​ 3,684,080 |
| Loss on derivative instruments, net of settlements | ​ | ​ 6,988,979 | ​ | ​ 8,737,714 |
| Consolidated Adjusted EBITDA | ​ | ​ 75,533,036 | ​ | ​ 74,113,012 |
| Adjusted EBITDA attributable to non-controlling interest | ​ | ​ (10,145,611) | ​ | ​ (16,179,650) |
| Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | ​ | ​ 65,387,425 | ​ | ​ 57,933,362 |
| Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ​ | ​ ​ | ​ | ​ ​ |
| Cash interest expense | ​ | ​ 4,051,203 | ​ | ​ 5,234,705 |
| Cash distribution on Series A preferred units | ​ | ​ 4,162,378 | ​ | ​ 3,800,296 |
| Distribution on Class B units | ​ | ​ 14,492 | ​ | ​ 20,847 |
| Cash available for distribution on common units | ​ | $57,159,352 | ​ | $48,877,514 |

| ​ ​ ​ Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units: | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 ​ ​ | ​ ​ ​ | ​ ​ 2024 ​ ​ |
| --- | --- | ---: | --- | ---: |
| Net cash provided by operating activities | ​ | $54,152,677 | ​ | $69,045,616 |
| Interest expense | ​ | 6,621,526 | ​ | 7,301,330 |
| Income tax expense | ​ | ​ 1,089,426 | ​ | ​ 922,568 |
| Impairment of oil and natural gas properties | ​ | — | ​ | (5,963,575) |
| Amortization of right-of-use assets | ​ | ​ (85,055) | ​ | (86,324) |
| Amortization of loan origination costs | ​ | (534,205) | ​ | (530,130) |
| Unit-based compensation | ​ | (3,861,815) | ​ | (3,684,080) |
| Forfeiture of restricted units | ​ | ​ 56,807 | ​ | — |
| Loss on derivative instruments, net of settlements | ​ | (6,988,979) | ​ | (8,737,714) |
| Changes in operating assets and liabilities: | ​ | ​ ​ | ​ | ​ ​ |
| Oil, natural gas and NGL receivables | ​ | 15,074,138 | ​ | (4,316,194) |
| Accounts receivable and other current assets | ​ | (16,361) | ​ | 1,149,530 |
| Accounts payable | ​ | 938,173 | ​ | (312,764) |
| Other current liabilities | ​ | (1,825,602) | ​ | 847,611 |
| Operating lease liabilities | ​ | ​ 61,512 | ​ | 91,769 |
| EBITDA | ​ | ​ 64,682,242 | ​ | ​ 55,727,643 |
| Add: | ​ | ​ ​ | ​ | ​ ​ |
| Impairment of oil and natural gas properties | ​ | — | ​ | 5,963,575 |
| Unit-based compensation | ​ | 3,861,815 | ​ | 3,684,080 |
| Loss on derivative instruments, net of settlements | ​ | 6,988,979 | ​ | 8,737,714 |
| Consolidated Adjusted EBITDA | ​ | ​ 75,533,036 | ​ | ​ 74,113,012 |
| Adjusted EBITDA attributable to non-controlling interest | ​ | ​ (10,145,611) | ​ | ​ (16,179,650) |
| Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | ​ | ​ 65,387,425 | ​ | ​ 57,933,362 |
| Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ​ | ​ ​ | ​ | ​ ​ |
| Cash interest expense | ​ | ​ 4,051,203 | ​ | ​ 5,234,705 |
| Cash distribution on Series A preferred units | ​ | ​ 4,162,378 | ​ | ​ 3,800,296 |
| Distribution on Class B units | ​ | ​ 14,492 | ​ | ​ 20,847 |
| Cash available for distribution on common units | ​ | $57,159,352 | ​ | $48,877,514 |

### Factors Affecting the Comparability of Our Results to Our Historical Results

Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below.

### Ongoing Acquisition Activities

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.

Further, the affiliates of our Sponsors and Contributing Parties have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such parties offer them to us. We may decide to fund any acquisition, including any potential dropdowns, with cash, common units, other equity securities, proceeds from borrowings under our secured revolving credit facility or the issuance of debt securities, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.

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.

### Impairment of Oil and Natural Gas Properties

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

We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 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.

### Results of Operations

The table below summarizes our revenue and expenses and production data for the periods indicated (unaudited).

| ​ ​ ​ Operating Results: Revenue | ​ ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ 2024 ​ ​ ​ ​ |
| --- | --- | ---: | --- | ---: |
| Oil, natural gas and NGL revenues | ​ | $89,951,203 | ​ | $87,499,509 |
| Lease bonus and other income | ​ | ​ 310,989 | ​ | ​ 438,796 |
| Loss on commodity derivative instruments, net | ​ | ​ (6,053,426) | ​ | ​ (5,704,361) |
| Total revenues | ​ | ​ 84,208,766 | ​ | ​ 82,233,944 |
| Costs and expenses | ​ | ​ ​ | ​ | ​ ​ |
| Production and ad valorem taxes | ​ | 5,375,429 | ​ | 6,531,901 |
| Depreciation and depletion expense | ​ | 31,118,095 | ​ | 38,166,806 |
| Impairment of oil and natural gas properties | ​ | — | ​ | 5,963,575 |
| Marketing and other deductions | ​ | 4,501,767 | ​ | 4,562,944 |
| General and administrative expense | ​ | 9,636,743 | ​ | 9,447,881 |
| Total costs and expenses | ​ | 50,632,034 | ​ | 64,673,107 |
| Operating income | ​ | 33,576,732 | ​ | 17,560,837 |
| Other expense | ​ | ​ ​ | ​ | ​ ​ |
| Interest expense | ​ | (6,621,526) | ​ | (7,301,330) |
| Other expense | ​ | (12,585) | ​ | — |
| Net income before income taxes | ​ | ​ 26,942,621 | ​ | ​ 10,259,507 |
| Income tax expense | ​ | ​ 1,089,426 | ​ | ​ 922,568 |
| Net income | ​ | ​ 25,853,195 | ​ | ​ 9,336,939 |
| Distribution and accretion on Series A preferred units | ​ | ​ (5,202,862) | ​ | ​ (5,256,287) |
| Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests | ​ | ​ (2,773,757) | ​ | ​ (890,849) |
| Distribution on Class B units | ​ | ​ (14,492) | ​ | ​ (20,847) |
| Net income attributable to common units of Kimbell Royalty Partners, LP | ​ | $17,862,084 | ​ | $3,168,956 |
| **Production Data:** | ​ | ​ ​ | ​ | ​ ​ |
| Oil (Bbls) | ​ | 749,744 | ​ | 804,589 |
| Natural gas (Mcf) | ​ | 6,618,953 | ​ | 7,413,069 |
| Natural gas liquids (Bbls) | ​ | 442,187 | ​ | 458,247 |
| Combined volumes (Boe) (6:1) | ​ | 2,295,090 | ​ | 2,498,348 |

### Comparison of the Three Months Ended March 31, 2025 to the Three Months Ended March 31, 2024

### Oil, Natural Gas and NGL Revenues

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.

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.

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 consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 7.4% or $5.72 per Bbl of oil and an increase of 92.6% or $1.99 per Mcf of natural gas for the comparable periods.

### Lease Bonus and Other Income

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.

### Loss on Commodity Derivative Instruments

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.

### Production and Ad Valorem Taxes

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.

### Depreciation and Depletion Expense

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.

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.

### Impairment

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.

### Marketing and Other Deductions

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.

### General and Administrative Expenses

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.

### Interest Expense

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.

### Income Tax Expense

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.

### Liquidity and Capital Resources

### Overview

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.

### Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in our partnership agreement and in the limited liability company agreement of the Operating Company. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

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.

We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.

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.

### Cash Flows

The table below presents our cash flows for the periods indicated.

| ​ ​ ​ Cash Flow Data: | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 ​ ​ | ​ ​ | ​ ​ 2024 ​ ​ |
| --- | --- | ---: | --- | ---: |
| Net cash provided by operating activities | ​ | $54,152,677 | ​ | $69,045,616 |
| Net cash used in investing activities | ​ | (222,949,985) | ​ | (91,368) |
| Net cash provided by (used in) financing activities | ​ | 170,256,669 | ​ | (60,267,298) |
| Net increase in cash and cash equivalents | ​ | $1,459,361 | ​ | $8,686,950 |

#### Operating Activities

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.

#### Investing Activities

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.

#### Financing Activities

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 million of restricted units repurchased for tax withholding.

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 million of restricted units repurchased for tax withholding, partially offset by $5.0 million of additional borrowings under our secured revolving credit facility.

### Indebtedness

On June 13, 2023, we entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated our existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million, with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.

On July 24, 2023, we entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The First Amendment amends the A&R Credit Agreement to, 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 Amendment No. 2 (the “Second Amendment”) to the A&R Credit Agreement. The Second Amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million.

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.

### Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. The non-controlling interest, which represents OpCo common unitholders’, are not subject to federal income taxes. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2024. Our estimates regarding treatment of our distributions are based on currently available information only and are subject to change, including with respect to prior quarters.

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

### New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies to our unaudited interim consolidated financial statements included elsewhere in this Quarterly Report.

### Critical Accounting Policies and Related Estimates

There have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our 2024 Form 10-K.

### Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2024 Form 10-K. As of March 31, 2025, we did not have any off-balance sheet arrangements. See Note 8—Leases to the unaudited interim consolidated financial statements for additional information regarding our operating leases.

## Market risk

As filed, 4,152 characters.

### Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect commodity prices to be even more volatile in the future as a result of ongoing international supply and demand imbalances and limited international storage capacity. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties.

Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.

Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 5—Derivatives to the unaudited interim consolidated financial statements in Item 1 of this Quarterly Report for additional information regarding our commodity derivatives.

### Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2025, we had seven counterparties to our derivative contracts, which are also lenders under our secured revolving credit facility.

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

### Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of March 31, 2025, we had total borrowings outstanding under our secured revolving credit facility of $299.0 million. The impact of a 1% increase in the interest rate on this amount of debt could result in an increase in interest expense of approximately $3.0 million annually, assuming that our indebtedness remained constant throughout the year.

### Inflation

Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2024 through March 31, 2025. However, inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.

## Controls and procedures

As filed, 1,674 characters.

### Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the management of our General Partner, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Disclosure controls and procedures are defined as controls designed to ensure that the information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2025.

### Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 3,134 characters.

In addition to the risks and uncertainties discussed in this Quarterly Report, included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks set out under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2024 Form 10-K. The following supplements and updates the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024. These risk factors could materially affect our business, financial condition and results of operations. The volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, these risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

*Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.*

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. Several recent tariff announcements by the U.S. federal government have been followed by announcements of limited exemptions and temporary pauses. These actions are unprecedented, have caused substantial uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods and commodities.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and increased volatility in commodity prices. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.

Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes, tariffs, trade agreements or policies, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.

Filed May 8, 2025.
Source: SEC EDGAR, the filing index for accession 0001558370-25-006965. Last ingested by Listed: Oct 24, 2026, 15:15 ET. No prices; not investment advice.