# TXO Partners, L.P.: Form 10-Q for the period ended Sep 30, 2025

- Company: [TXO Partners, L.P.](/companies/txo.md) (CIK 1559432)
- Form: 10-Q
- Filed: 2025-11-04
- Accepted by EDGAR: Nov 4, 2025, 16:38 ET
- Period: 2025-09-30
- Accession: 0001559432-25-000108
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1559432/000155943225000108/txo-20250930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1559432/000155943225000108/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-07-01 to 2025-09-30 | $90.6m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 9 months, 2025-01-01 to 2025-09-30 | $259.4m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 3 months, 2025-07-01 to 2025-09-30 | $3.8m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2025-01-01 to 2025-09-30 | −$3.5m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-07-01 to 2025-09-30 | $4.5m | us-gaap:InterestExpenseNonoperating |
| Interest expense | 9 months, 2025-01-01 to 2025-09-30 | $10.7m | us-gaap:InterestExpenseNonoperating |
| Net income | 3 months, 2025-07-01 to 2025-09-30 | $4.4m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2025-01-01 to 2025-09-30 | $6.6m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-07-01 to 2025-09-30 | $0.08 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2025-01-01 to 2025-09-30 | $0.14 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-07-01 to 2025-09-30 | $0.08 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2025-01-01 to 2025-09-30 | $0.14 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-07-01 to 2025-09-30 | 55,807,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2025-01-01 to 2025-09-30 | 49,006,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2025-01-01 to 2025-09-30 | $85.7m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2025-09-30 | $5.3m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-09-30 | $76.9m | us-gaap:AssetsCurrent |
| Total assets | at 2025-09-30 | $1.38bn | us-gaap:Assets |
| Current liabilities | at 2025-09-30 | $160.6m | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2025-09-30 | $271.1m | us-gaap:LongTermDebt |

## Management's discussion and analysis

As filed, 47,243 characters.

*The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in Item 1 of this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited consolidated financial statements and notes thereto and the related “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in our Annual Report on Form 10-K for the year ended December 31, 2024.*

*Unless otherwise stated or the context indicates otherwise, references in this Quarterly Report to “our general partner” refers to TXO Partners GP, LLC, a Delaware limited liability company, and the terms “partnership,” the “Company,” “we,” “our,” “us” or similar terms refer to TXO Partners, L.P., a Delaware limited partnership (“TXO Partners”) and its subsidiaries. Unless otherwise indicated, throughout this discussion the term “MBoe” refers to thousands of barrels of oil equivalent quantities produced for the indicated period, with natural gas and NGL quantities converted to Bbl on an energy equivalent ratio of six Mcf to one barrel of oil.*

### Cautionary Statement Regarding Forward-Looking Statements

Some of the information in this Quarterly Report on Form 10-Q may contain “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this Quarterly Report on Form 10-Q.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and natural gas liquids (“NGL”). We disclose important factors that could cause our actual results to differ materially from our expectations as discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Quarterly Report on Form 10-Q. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statement include:

- commodity price volatility;
- the impact of epidemics, outbreaks or other public health events, and the related effects on financial markets, worldwide economic activity and our operations;
- uncertainties about our estimated oil, natural gas and NGL reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production;
- the concentration of our operations in the Permian Basin, the San Juan Basin and the Williston Basin;
- difficult and adverse conditions in the domestic and global capital and credit markets;
- lack of transportation and storage capacity as a result of oversupply, government regulations or other factors;
- lack of availability of drilling and production equipment and services;
- potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity risks;
- failure to realize expected value creation from property acquisitions and trades;
- access to capital and the timing of development expenditures;
- environmental, weather, drilling and other operating risks;
- regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas;
- competition in the oil and natural gas industry;
- loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production;
- our ability to service our indebtedness;
- cost inflation;
- changes to U.S. and foreign governmental regulation, taxation and tariffs;
- our ability to integrate the acquired assets and realize the anticipated benefits of the WRE Acquisition, including, among other things, operating efficiencies, revenue synergies and other cost savings;
- political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, the Israel-Hamas war, attacks in the Red Sea and other continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;
- evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insider or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and
- risks related to our ability to expand our business, including through the recruitment and retention of qualified personnel.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, our reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report on Form 10-Q occur, or should underlying assumptions prove to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report on Form 10-Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

### Overview

We are an independent oil and natural gas company focused on the acquisition, development, optimization and exploitation of conventional and unconventional oil, natural gas and natural gas liquid reserves in North America. Our properties are predominately located in the Permian Basin of New Mexico and Texas, the San Juan Basin of New Mexico and Colorado and the Williston Basin of Montana and North Dakota.

### Market Outlook

The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2024 through September 30, 2025, NYMEX prices for crude oil and natural gas reached a high of $86.91 per Bbl and $4.49 per MMBtu, respectively, and a low of $57.13 per Bbl and $1.58 per MMBtu, respectively. Oil prices increased in the first half of 2024 due to hostilities in the Middle East and higher global consumption. However, increased supply led to lower prices in the second half of 2024 and into 2025. These declines accelerated in April due to the tariff announcement, the increased expectation for a global recession and additional supply. WTI crude oil prices have been volatile reaching a high of $86.91 per Bbl in April 2024 before declining to $57.52 per Bbl as of October 20, 2025. Natural gas prices reached a high of $4.49 per MMbtu in March 2025 before declining to $3.40 per MMbtu as of October 20, 2025.

We expect the crude oil and natural gas markets will continue to be volatile in the future. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production. Please see “Risk Factors--Risks Related to the Natural Gas, NGL and Oil Industry and Our Business--Commodity prices are volatile--A sustained decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

With our anticipated cash flows from our long-lived property base, we intend to provide dynamic allocation of funds to prudently meet our goals. These goals include the highest projected economic returns on our capital budget, acquisition opportunities that fulfill our strategy, and cash distributions for the life of our legacy assets. From time to time, we may choose to prioritize the repayment of debt incurred in acquisitions to support the longer-term financial stewardship of our business. At other times, given fluctuations in industry costs and commodity prices, we may modify our capital budget or cash balances to shift funds towards cash distributions. We will use all of these tools to support our underlying strategy as a “production and distribution” enterprise.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, tariffs, the availability and cost of credit and the United States financial markets and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Rising inflation has been pervasive for the last several years, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate, inflation continues to run higher than the Federal Reserve target, resulting in higher costs. We continue to undertake actions and implement plans to address these pressures and protect the requisite access to commodities and services, however, these mitigation efforts may not succeed or be insufficient. Nevertheless, we expect for the foreseeable future to experience inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent these higher costs do not begin to reverse or start to increase again, we may experience a higher cost environment going forward. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

We are taking actions to mitigate inflationary pressures. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies, which are critical to many of our operations. However, these mitigation efforts may not succeed or be insufficient.

### How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our operations, including:

- production volumes;
- realized prices on the sale of oil, NGLs and natural gas;
- production expenses;
- acquisition and development expenditures;
- Adjusted EBITDAX; and
- Cash Available for Distribution.

### Non-GAAP Financial Measures

### Adjusted EBITDAX

We include in this Quarterly Report the non-GAAP financial measure Adjusted EBITDAX and provide our calculation of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDAX as net income (loss) before (1) interest income, (2) interest expense, (3) depreciation, depletion and amortization, (4) impairment expenses, (5) accretion of discount on asset retirement obligations, (6) exploration expenses, (7) unrealized (gains) losses on commodity derivative contracts, (8) non-cash incentive compensation, (9) non-cash (gain) loss on forgiveness of debt and (10) certain other non-cash expenses.

Adjusted EBITDAX is used as a supplemental financial measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to more effectively evaluate our operating performance and our results of operation from period to period and against our peers without regard to financing methods, capital structure or historical cost basis. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX 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. Adjusted EBITDAX is not a measurement of our financial performance under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as indicators of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies.

### Cash Available for Distribution

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial measure used by our management and by external users of our financial statements, such as investors, lenders and others (including industry analysts and rating agencies who will be using such measure), to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as Adjusted EBITDAX less net cash interest expense, exploration expense, non-recurring (gain) / loss and development costs. Development costs include all of our capital expenditures made for oil and gas properties, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances. Cash available for distribution is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by or used in operating activities as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measures most directly comparable to cash available for distribution are net income and net cash provided by operating activities. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities.

You should not infer from our presentation of Adjusted EBITDAX that its results will be unaffected by unusual or non-recurring items. You should not consider Adjusted EBITDAX or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDAX and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDAX and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

### Reconciliation of Adjusted EBITDAX and Cash Available for Distribution to GAAP Financial Measures

*(in thousands)*

|  | Three Months Ended September 30, 2025 | 2024 | Nine Months Ended September 30, 2025 | 2024 |
| --- | ---: | ---: | ---: | ---: |
| **Net income** | $4,352 | $203 | $6,633 | $13,278 |
| Interest expense | 4,505 | 1,860 | 10,697 | 3,885 |
| Interest income | (113) | (700) | (516) | (947) |
| Depreciation, depletion and amortization | 23,697 | 13,573 | 66,810 | 34,422 |
| Accretion of discount in asset retirement obligation | 3,982 | 2,926 | 11,623 | 8,491 |
| Exploration expense | 91 | 20 | 224 | 214 |
| Non-cash derivative (gain) loss | (7,250) | 549 | (7,094) | 3,547 |
| Non-cash incentive compensation | 3,468 | 1,596 | 12,835 | 4,569 |
| Non-recurring (gain)/loss | $18 | $135 | $23 | $225 |
| **Adjusted EBITDAX** | $32,750 | $20,162 | $101,235 | $67,684 |
| Cash Interest expense | (4,167) | (1,607) | (9,853) | (3,239) |
| Cash Interest income | 113 | 700 | 516 | 947 |
| Exploration expense | (91) | (20) | (224) | (214) |
| Development costs | (21,062) | (2,668) | (36,018) | (10,866) |
| **Cash Available for Distribution** | $7,543 | $16,567 | $55,656 | $54,312 |
| **Net cash provided by operating activities** | $28,271 | $20,710 | $85,735 | $68,792 |
| Changes in operating assets and liabilities | 334 | (1,475) | 5,939 | (3,614) |
| Development costs | (21,062) | (2,668) | (36,018) | (10,866) |
| **Cash Available for Distribution** | $7,543 | $16,567 | $55,656 | $54,312 |

22

### Results of Operations

### Three Months Ended September 30, 2025 Compared to the Three Months Ended September 30, 2024

*(in thousands)*

| REVENUES | Three Months Ended September 30, 2025 | 2024 |
| --- | ---: | ---: |
| Oil and condensate | $66,330 | $56,111 |
| Natural gas liquids | 7,504 | 7,195 |
| Natural gas | 27,042 | 5,425 |
| Total Revenues | 100,876 | 68,731 |
| **EXPENSES** |  |  |
| Production | 47,864 | 39,437 |
| Exploration | 91 | 20 |
| Taxes, transportation and other | 16,648 | 14,466 |
| Depreciation, depletion and amortization | 23,697 | 13,573 |
| Accretion of discount in asset retirement obligation | 3,982 | 2,926 |
| General and administrative | 4,834 | 3,275 |
| Total Expenses | 97,116 | 73,697 |
| **OPERATING (LOSS) INCOME** | 3,760 | (4,966) |
| **OTHER INCOME (EXPENSE)** |  |  |
| Other income | 4,984 | 6,329 |
| Interest income | 113 | 700 |
| Interest expense | (4,505) | (1,860) |
| Total Other Income | 592 | 5,169 |
| **NET INCOME** | $4,352 | $203 |

23

The following table provides a summary of our sales volumes, average prices (both including and excluding the effects of derivatives) and operating expenses on a per Boe basis for the periods indicated:

| Sales: | Three Months Ended September 30, 2025 | 2024 |
| --- | ---: | ---: |
| Oil and condensate sales (MBbls) | 1,053 | 699 |
| Natural gas liquids sales (MBbls) | 387 | 308 |
| Natural gas sales (MMcf) | 7,116 | 6,587 |
| Total (MBoe) | 2,626 | 2,105 |
| Total (MBoe/d) | 29 | 23 |
| **Average sales prices:** |  |  |
| Oil and condensate excluding the effects of derivatives (per Bbl) | $62.80 | $72.13 |
| Oil and condensate (per Bbl) (1) | $63.00 | $80.28 |
| Natural gas liquids excluding the effects of derivatives (per Bbl) | $19.34 | $23.33 |
| Natural gas liquids (per Bbl) (2) | $19.38 | $23.33 |
| Natural gas excluding the effects of derivatives (per Mcf) | $2.38 | $1.77 |
| Natural gas (per Mcf) (3) | $3.80 | $0.82 |
| **Expense per Boe:** |  |  |
| Production | $18.23 | $18.73 |
| Taxes, transportation and other | $6.34 | $6.87 |
| Depreciation, depletion and amortization | $9.02 | $6.45 |
| General and administrative expenses | $1.84 | $1.56 |

(1) Oil and condensate prices include both realized gains and losses and unrealized gains from derivatives. Unrealized gains were $0.3 million for the three months ended September 30, 2025 and $5.7 million for the three months ended September 30, 2024. Realized losses were $0.1 million for the three months ended September 30, 2025 and there were no realized losses for the three months ended September 30, 2024.

(2) Natural gas liquids prices include both realized gains and unrealized gains and losses from derivatives. Unrealized gains were $15 thousand for the three months ended September 30, 2025 and there were no unrealized gains for the three months ended September 30, 2024. There were no realized gains for the three months ended September 30, 2025 and less than $1 thousand for the three months ended September 30, 2024.

(3) Natural gas prices include both realized gains and unrealized gains and losses from derivatives. Unrealized gains were $6.9 million for the three months ended September 30, 2025 and unrealized losses were $6.2 million for the three months ended September 30, 2024. Realized gains were $3.1 million for the three months ended September 30, 2025 and $5 thousand for the three months ended September 30, 2024.

### Revenues

Revenues increased $32.1 million, or 47%, from $68.7 million for the three months ended September 30, 2024 to $100.9 million for the three months ended September 30, 2025. Revenue increased $25.0 million due to an increase in production of 521 MBoe primarily as a result of the acquisition of producing assets in the Williston Basin being offset by natural declines in San Juan Basin and Permian Basin. Additionally, a 34% increase in the average selling price of natural gas, excluding the effects of derivatives, resulted in an increase in revenue of $4.0 million. Finally, we recognized net gains on our hedging activity of $10.9 million, of which $7.8 million were unrealized gains and $3.1 million were realized gains. These increases were partially offset by a decrease in the average selling price on oil, excluding the effects of derivatives, on oil of 13% which resulted in a decrease in revenue of $6.5 million and on NGLs of 17% which resulted in a decrease in revenue of $1.2 million.

### Production expenses

Production expenses increased $8.4 million, or 21%, from $39.4 million for the three months ended September 30, 2024 to $47.9 million for the three months ended September 30, 2025. Of this increase, $8.0 million is attributable to production from the Williston Basin acquisitions.

On a per unit basis, production expenses decreased from $18.73 per Boe sold for the three months ended September 30, 2024 to $18.23 per Boe sold for the three months ended September 30, 2025. The decrease is primarily related to an increase in production of 521 MBoe partially offset by increased costs attributable to production from the Williston Basin acquisitions.

### Taxes, transportation, and other

Taxes, transportation, and other increased $2.2 million, or 15%, from $14.5 million for the three months ended September 30, 2024 to $16.6 million for the three months ended September 30, 2025. The increase is primarily attributable to the increase in production and higher natural gas prices partially offset by decreased oil and NGL prices.

On a per unit basis, taxes, transportation, and other decreased from $6.87 per Boe sold for the three months ended September 30, 2024 to $6.34 per Boe sold for the three months ended September 30, 2025. The decrease is primarily related to increased production partially offset by increased costs.

### Depreciation, depletion, and amortization

Depreciation, depletion, and amortization (“DD&A”) increased $10.1 million, or 75%, from $13.6 million for the three months ended September 30, 2024 to $23.7 million for the three months ended September 30, 2025. The increase is primarily attributable to the DD&A from increased production associated with the Williston Basin acquisitions of $8.9 million which has a higher rate than the historical properties, and a higher rate on our historical properties partially offset by decreased production.

On a per unit basis, depreciation, depletion, and amortization increased from $6.45 per Boe sold for the three months ended September 30, 2024 to $9.02 per Boe sold for the three months ended September 30, 2025. The increase is primarily related to the production associated with the Williston Basin acquisitions, which has a higher rate than the historical properties.

### General and administrative

General and administrative (“G&A”) expenses increased $1.6 million, or 48%, from $3.3 million for the three months ended September 30, 2024 to $4.8 million for the three months ended September 30, 2025. The increase is primarily attributable to higher personnel costs of $1.1 million primarily due to amortization of unit awards and additional public company costs.

On a per unit basis, G&A expense increased from $1.56 per Boe sold for the three months ended September 30, 2024 to $1.84 per Boe sold for the three months ended September 30, 2025. The increase is primarily related to increased costs partially offset by increased production.

### Other income

Other income decreased $1.3 million, or 21%, from $6.3 million for the three months ended September 30, 2024 to $5.0 million for the three months ended September 30, 2025. The decrease is primarily attributable to lower CO2 and plant income of $1.4 million as a result of third-party pipeline disruptions. The CO2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO2 assets in Colorado.

### Interest expense

Interest expense increased $2.6 million, or 142%, from $1.9 million for the three months ended September 30, 2024 to $4.5 million for the three months ended September 30, 2025. The increase is primarily attributable to increased borrowings and amortization of capitalized debt costs partially offset by a lower average interest rate.

### Nine Months Ended September 30, 2025 Compared to the Nine Months Ended September 30, 2024

*(in thousands)*

| REVENUES | Nine Months Ended September 30, 2025 | 2024 |
| --- | ---: | ---: |
| Oil and condensate | $190,379 | $136,944 |
| Natural gas liquids | 23,958 | 20,367 |
| Natural gas | 60,743 | 36,167 |
| Total Revenues | 275,080 | 193,478 |
| **EXPENSES** |  |  |
| Production | 133,469 | 108,959 |
| Exploration | 224 | 214 |
| Taxes, transportation and other | 49,763 | 43,240 |
| Depreciation, depletion and amortization | 66,810 | 34,422 |
| Accretion of discount in asset retirement obligation | 11,623 | 8,491 |
| General and administrative | 16,729 | 10,520 |
| Total Expenses | 278,618 | 205,846 |
| **OPERATING (LOSS) INCOME** | (3,538) | (12,368) |
| **OTHER INCOME (EXPENSE)** |  |  |
| Other income | 20,352 | 28,584 |
| Interest income | 516 | 947 |
| Interest expense | (10,697) | (3,885) |
| Total Other Income | 10,171 | 25,646 |
| **NET INCOME** | $6,633 | $13,278 |

26

The following table provides a summary of our sales volumes, average prices (both including and excluding the effects of derivatives) and operating expenses on a per Boe basis for the periods indicated:

| Sales: | Nine Months Ended September 30, 2025 | 2024 |
| --- | ---: | ---: |
| Oil and condensate sales (MBbls) | 2,829 | 1,775 |
| Natural gas liquids sales (MBbls) | 1,050 | 889 |
| Natural gas sales (MMcf) | 20,657 | 20,694 |
| Total (MBoe) | 7,322 | 6,112 |
| Total (MBoe/d) | 27 | 22 |
| **Average sales prices:** |  |  |
| Oil and condensate excluding the effects of derivatives (per Bbl) | $64.22 | $75.35 |
| Oil and condensate (per Bbl) (1) | $67.30 | $77.17 |
| Natural gas liquids excluding the effects of derivatives (per Bbl) | $22.79 | $22.92 |
| Natural gas liquids (per Bbl) (2) | $22.81 | $22.92 |
| Natural gas excluding the effects of derivatives (per Mcf) | $2.60 | $1.96 |
| Natural gas (per Mcf) (3) | $2.94 | $1.75 |
| **Expense per Boe:** |  |  |
| Production | $18.23 | $17.83 |
| Taxes, transportation and other | $6.80 | $7.07 |
| Depreciation, depletion and amortization | $9.12 | $5.63 |
| General and administrative expenses | $2.28 | $1.72 |

(1) Oil and condensate prices include both realized gains and losses and unrealized gains from derivatives. Unrealized gains were $6.7 million for the nine months ended September 30, 2025 and $8.9 million for the nine months ended September 30, 2024. Realized gains were $2.0 million for the nine months ended September 30, 2025 and realized losses were $5.6 million for the nine months ended September 30, 2024.

(2) Natural gas liquids prices include both realized gains and unrealized losses from derivatives. Unrealized gains were $14 thousand for the nine months ended September 30, 2025 and unrealized losses were $0.5 million for the nine months ended September 30, 2024. There were no realized gains for the nine months ended September 30, 2025 and $0.5 million for the nine months ended September 30, 2024.

(3) Natural gas prices include both realized gains and unrealized losses from derivatives. Unrealized gains were $0.4 million for the nine months ended September 30, 2025 and unrealized losses were $11.9 million for the nine months ended September 30, 2024. Realized gains were $6.6 million for the nine months ended September 30, 2025 and $7.4 million for the nine months ended September 30, 2024.

### Revenues

Revenues increased $81.6 million, or 42%, from $193.5 million for the nine months ended September 30, 2024 to $275.1 million for the nine months ended September 30, 2025. The increase was primarily attributable to a 1,210 MBoe increase in production which resulted in a $71.3 million increase in revenue primarily as a result of the acquisition of producing assets in the Williston Basin being offset by natural declines in San Juan Basin and Permian Basin. Additionally, a 33% increase in the average selling price of natural gas, excluding the effects of derivatives, resulted in an increase in revenue of $13.2 million. Finally, we recognized net gains on our hedging activity of $16.9 million, of which $10.6 million were unrealized gains and $6.3 million were realized gains. These increases were partially offset by a decrease in the average selling price, excluding the effects of derivatives, on oil of 15% and NGLs of 1%, which resulted in a decrease in revenue of $19.8 million on oil and $0.1 million on NGLs.

### Production expenses

Production expenses increased $24.5 million, or 22%, from $109.0 million for the nine months ended September 30, 2024 to $133.5 million for the nine months ended September 30, 2025. Of this increase, $23.5 million is attributable to production from the Williston Basin acquisitions.

On a per unit basis, production expenses increased from $17.83 per Boe sold for the nine months ended September 30, 2024 to $18.23 per Boe sold for the nine months ended September 30, 2025. The increase is primarily related to the increased costs per Boe from our historical properties as decreased production and increased maintenance, energy, labor and chemical costs in these properties resulted in higher costs per Boe.

### Taxes, transportation, and other

Taxes, transportation, and other increased $6.5 million, or 15%, from $43.2 million for the nine months ended September 30, 2024 to $49.8 million for the nine months ended September 30, 2025. The increase is primarily attributable to the increase in production and natural gas prices partially offset by decreased oil and NGL prices.

On a per unit basis, taxes, transportation, and other decreased from $7.07 per Boe sold for the nine months ended September 30, 2024 to $6.80 per Boe sold for the nine months ended September 30, 2025. The decrease is primarily attributable to increased production partially offset by increased costs.

### Depreciation, depletion, and amortization

Depreciation, depletion, and amortization increased $32.4 million, or 94%, from $34.4 million for the nine months ended September 30, 2024 to $66.8 million for the nine months ended September 30, 2025. The increase is attributable to the DD&A from increased production associated with the Williston Basin acquisitions of $28.6 million which has a higher rate than the historical properties, and a higher rate on our historical properties partially offset by decreased production.

On a per unit basis, depreciation, depletion, and amortization increased from $5.63 per Boe sold for the nine months ended September 30, 2024 to $9.12 per Boe sold for the nine months ended September 30, 2025. The increase is primarily related to the production associated with the Williston Basin acquisitions, which has a higher rate than the historical properties.

### General and administrative

General and administrative (“G&A”) expenses increased $6.2 million, or 59%, from $10.5 million for the nine months ended September 30, 2024 to $16.7 million for the nine months ended September 30, 2025. The increase is primarily attributable to higher personnel costs of $4.3 million due primarily to amortization of unit awards and increased public company costs and acquisition expenses.

On a per unit basis, G&A expense increased from $1.72 per Boe sold for the nine months ended September 30, 2024 to $2.28 per Boe sold for the nine months ended September 30, 2025. The increase is primarily related to increased costs partially offset by increased production.

### Other income

Other income decreased $8.2 million, or 29%, from $28.6 million for the nine months ended September 30, 2024 to $20.4 million for the nine months ended September 30, 2025. The decrease is primarily attributable to the absence of $4.0 million in bonus payments on term assignment of leases and lower CO2 and plant income of $4.1 million. The CO2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO2 assets in Colorado.

### Interest expense

Interest expense increased $6.8 million, or 175%, from $3.9 million for the nine months ended September 30, 2024 to $10.7 million for the nine months ended September 30, 2025. The increase is primarily attributable to the increased borrowings and amortization of capitalized loan costs partially offset by a lower average interest rate.

### Liquidity and Capital Resources

Our primary sources of liquidity and capital will be cash flows generated by operating activities and borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility were $264.0 million at September 30, 2025 and $150.0 million at December 31, 2024, and the remaining availability under our Credit Facility was $146.0 million at September 30, 2025 and $125.0 million at December 31, 2024. Additionally, we had negative net working capital (including cash and excluding the effects of derivative instruments) of $86.3 million at September 30, 2025 and negative net working capital of $2.5 million at December 31, 2024.

On May 15, 2025, we completed the Offering, which resulted in proceeds of approximately $165.6 million net of underwriting discounts, commissions and other costs. On May 19, 2025, we completed the sale of an additional 1,750,000 common units at a price of $15.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the Offering, resulting in additional proceeds of approximately $23.9 million net of underwriting discounts, commissions and other costs. We used the net proceeds from the Offering to fund a portion of the cash consideration for the WRE Acquisition. Prior to the closing of the WRE Acquisition, we used a portion of these proceeds to repay outstanding borrowings under the Credit Facility and to fund the deposit on the WRE Acquisition.

All of the funds, or $233.8 million, to close the WRE Acquisition were borrowings under our Credit Facility, which increased our net-debt-to-EBITDAX ratio to between 1.0 times and 1.5 times.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero. Our third quarter distribution of $0.35 per unit with respect to cash available for distribution for the three months ended September 30, 2025, was declared on November 4, 2025 and will be paid on November 21, 2025 to unitholders of record on November 14, 2025.

Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions were $305.4 million for the nine months ended September 30, 2025 and $273.0 million for the nine months ended September 30, 2024.

In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

We incurred costs of approximately $46.1 million for drilling, completion and recompletion activities and facilities costs in the nine months ended September 30, 2025 and we have budgeted approximately $65.0 million for such costs in 2025.

The amount and timing of these capital expenditures is substantially within our control and subject to management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to the prevailing and anticipated prices for oil, NGLs and natural gas, the availability of necessary equipment, infrastructure and capital, seasonal conditions and drilling and acquisition costs. Any postponement or elimination of our development program could result in a reduction of proved reserve volumes, production and cash flow, including distributions to unitholders.

Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our distributions, meet our debt obligations and fund our 2025 capital development programs from cash flow from operations, the Offering and borrowings under our Credit Facility.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or distributions to unitholders. Alternatively, we may fund these expenditures using borrowings under our Credit Facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us, finance the capital expenditures necessary to maintain our production or proved reserves, or make distributions to unitholders.

### Cash flows

The following table summarizes our cash flows for the periods indicated (in thousands):

|  | Nine Months Ended September 30, 2025 | 2024 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $85,735 | $68,792 |
| Net cash used by investing activities | (305,432) | (273,012) |
| Net cash provided by financing activities | 217,700 | 203,561 |

### Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

### Net cash provided by operating activities

Net cash provided by operating activities increased $16.9 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 due to improved operating results, excluding the effects of derivatives, primarily due to increased revenues partially offset by increased costs.

### Net cash used by investing activities

Net cash used by investing activities increased $32.4 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 due to increased development costs of $25.2 million and an increase in proved property acquisitions of $8.1 million partially offset by a decrease in other asset additions of $0.7 million.

### Net cash provided by financing activities

*(in thousands)*

|  | Nine Months Ended September 30, 2025 | 2024 |
| --- | ---: | ---: |
| Proceeds from long-term debt | $360,500 | $222,000 |
| Payments on long-term debt | (246,500) | (95,000) |
| Net proceeds from public offering | 189,502 | 141,245 |
| Proceeds from sale of units to cover withholding taxes | 1,215 | 930 |
| Withholding taxes paid on vesting of restricted units | (2,358) | (851) |
| Debt issuance costs | (2,429) | (3,173) |
| Distributions | (82,230) | (61,590) |
| Net cash provided by financing activities | $217,700 | $203,561 |

Net cash provided by financing activities increased $14.1 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 primarily due to an increase in net proceeds from public offering of $48.3 million partially offset by increased net repayments under our Credit Facility of $13.0 million and increased distributions to unitholders of $20.6 million.

### Revolving credit agreement

On July 31, 2025, we entered into Amendment No. 5 to our Credit Facility with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. We use the Credit Facility for general corporate purposes. Amendment No. 5 increased the borrowing base from $275 million to $410 million, extended the maturity date to August 30, 2029 and joined certain new Lenders to the Credit Facility.

Our Credit Facility contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on merging or consolidating with another company, limitations on making certain restricted payments, limitations on investments, limitations on paying distributions on, redeeming, or repurchasing common units, limitations on entering into transactions with affiliates, and limitations on asset sales. The Credit Facility also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.

At our election, interest on borrowings under the credit facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). The weighted average interest rate on Credit Facility borrowings was 8.0% in the nine months ended September 30, 2025.

We are required to maintain (i) a current ratio (the ratio of current assets to current liabilities) greater than 1.0 to 1.0, which for purposes of this definition includes availability under the Credit Facility but excludes the fair value of derivative instruments, and (ii) a ratio of total net debt-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-to-EBITDAX ratio, total net debt is total debt for borrowed money (including capital leases and purchase money debt) minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means the sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Under the terms

of the Credit Facility, we were in compliance with all of our debt covenants as of September 30, 2025. Additionally, we

believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this

report.

We had $264 million debt outstanding and $146 million available under our Credit Facility as of September 30, 2025.

### Contractual obligations and commitments

We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses.

#### Derivative contracts

We have entered into derivative instruments to hedge our exposure to commodity price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of September 30, 2025, the current liability related to such contracts was $8.5 million and the long-term liability related to such contracts was $2.1 million. Such payments will generally be funded by higher prices received from the sale of oil, NGLs and natural gas. For further information on derivative contracts, see Note 10 in the financial statements included elsewhere in this Quarterly Report.

#### Asset Retirement Obligation

At September 30, 2025, we had asset retirement obligations of $208.9 million inclusive of a current portion of $3.5 million. For further information on asset retirement obligations, see Note 7 in the financial statements included elsewhere in this Quarterly Report.

### Critical Accounting Policies

There has been no change in our critical accounting policies from those disclosed in our Annual Report on Form 10-K filed with the SEC on March 4, 2025.

## Market risk

As filed, 5,132 characters.

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Also, gains and losses on these instruments are generally offset by losses and gains on the offsetting expenses.

### Commodity price risk

Our major market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production. Pricing for oil, NGLs, and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, NGL, and natural gas production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil, NGL and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL and natural gas production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.

As of September 30, 2025, the fair market value of our oil, NGL and natural gas derivative contracts was a net asset of $1.7 million. Based upon our open commodity derivative positions at September 30, 2025, a hypothetical 10% change in the NYMEX WTI, Henry Hub prices, OPIS prices and basis prices would change our net oil, NGL and natural gas derivative asset by approximately $37.2 million.

*(in thousands)*

|  | Fair Value at September 30, 2025 | Hypothetical Price Increase or Decrease of 10% Price Change |
| --- | ---: | ---: |
| Derivative asset (liability) – Crude Oil | $9,361 | $24,872 |
| Derivative asset (liability) – Natural Gas Liquids | $14 | $37 |
| Derivative asset (liability) – Natural Gas | $(7,673) | $12,318 |
| Net derivative asset | $1,702 | $37,227 |

The hypothetical change in fair value could be a gain or loss depending on whether prices increase or decrease.

### Counterparty and customer credit risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds in major financial institutions. We often have balances in excess of the federally insured limits.

We sell oil, NGL and natural gas production to various types of customers. Credit is extended based on an evaluation of the customer’s financial condition and historical payment record. The future availability of a ready market for our production depends on numerous factors outside of our control, none of which can be predicted with certainty. For the years ended December 31, 2024 and December 31, 2023, we had two and two customers, respectively, that each accounted for more than 10% of total revenues. We do not believe the loss of any single purchaser would materially impact our operating results because oil, NGLs and natural gas are fungible products with well-established markets and numerous purchasers.

At September 30, 2025, we had commodity derivative contracts with counterparties. We are currently not required to provide collateral or other security to counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, we use master netting arrangements to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review.

### Interest rate risk

At September 30, 2025, we had $264.0 million of variable rate debt outstanding. Assuming no change in the amount

outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be

approximately $2.6 million per year. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement.”

## Controls and procedures

As filed, 1,599 characters.

### Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Principal Executive Officers and Principal Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of September 30, 2025. Based on this evaluation, our Principal Executive Officers and Principal Financial Officer concluded that as of September 30, 2025, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized, and reported as and when required, and that such information is accumulated and communicated to our management, including our Principal Executive Officers and Principal Financial Officer, to allow timely decisions regarding its required disclosure. Based on the evaluation of our disclosure controls and procedures as of September 30, 2025, our Principal Executive Officers and Principal Financial Officer have concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

### Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 159 characters.

There have been no material changes in the risk factors disclosed under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024.

Filed Nov 4, 2025.
Source: SEC EDGAR, the filing index for accession 0001559432-25-000108. Last ingested by Listed: Nov 3, 2026, 19:47 ET. No prices; not investment advice.