Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Unaudited Condensed Consolidated Financial Statements and accompanying notes in “Item 1. Financial Statements” contained herein and in “Item 1A. Risk Factors” of our 2025 Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.
Overview
We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on the reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries.
The Company’s assets have historically consisted primarily of producing oil and natural gas properties located in Oklahoma, the Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana and the Eagle Ford (non-op). The Company divested its assets in Oklahoma, East Texas/North Louisiana and the Eagle Ford (non-op) during the year ended December 31, 2025. As of March 31, 2026, the Company properties consist of its Bairoil and Beta oil and NGL producing properties. The oil and NGL properties are located in mature oil reservoirs. As of March 31, 2026, the Company is the operator of record for properties containing 100% of its total estimated proved reserves.
Industry Trends
We continue to monitor the impact of the actions of the Organization of the Petroleum Exporting Countries and other large producing nations; the Russia-Ukraine conflict; conflicts or entanglements in the Middle East or South America; global inventories of oil and natural gas and the uncertainty associated with recovering oil demand; inflation and future monetary policy; and governmental policies aimed at transitioning towards lower carbon energy. The Russia-Ukraine conflict and conflicts or entanglements in the Middle East and South America continue to evolve, and the extent to which these events may impact our business, results of operations, financial condition and cash flows will depend on future developments, which are highly uncertain and cannot be predicted with confidence.
Divestiture Summary
In 2025, the Company worked to simplify its portfolio and strengthen its balance sheet. The Company made significant progress towards this goal throughout 2025, with the first transaction occurring in the first quarter of 2025 with the East Texas Haynesville monetization. Throughout the remainder of 2025, the Company completed additional divestiture transactions, including monetization and asset sales. These transactions continued management’s efforts to simplify the Company’s asset base. Management believes the divestiture transactions strengthened liquidity and further streamlined the Company’s asset portfolio. None of the asset dispositions qualified as discontinued operations.
Recent Developments
Beta Royalty Relief
On, April 30, 2026, the Bureau of Safety and Environmental Enforcement (“BSEE”) informed the Company that it had been approved for End-of-Life Royalty Relief for the Company’s interests in three Pacific Outer Continental Shelf blocks (P-300, P-0301, and P-0306), referred to as the Beta unit in the Beta Field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. The royalty relief is effective beginning May 1, 2026 for the Beta leases. On the Company’s two primary producing leases, the royalty rate was reduced from approximately 25% to 12.5%, and on the third lease, the royalty rate was reduced from 16.67% to 8.33%.
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Royalty relief rates will be suspended in months in which the rolling 12-month weighted average NYMEX oil and Henry Hub gas price exceeds $79.65 per BOE, which represents a 25% premium to the average realized price recognized by the Company during the qualification period. Royalty relief will end in the event that the rolling 12-month weighted average commodity prices exceed $79.65 per BOE, or if monthly production doubles the qualifying months’ average for 12 consecutive months.
Business Environment and Operational Focus
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production; (iii) cash settlements on our commodity derivatives; (iv) lease operating expense; (v) gathering, processing and transportation; (vi) general and administrative expense; and (vii) Adjusted EBITDA (as defined below).
Sources of Revenues
Our revenues are derived from the sale of oil production, as well as the sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. Oil and NGL prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in oil prices on revenues, we intend to periodically enter into derivative contracts that fix the future prices received. At the end of each period, the fair value of these commodity derivative instruments is estimated and because hedge accounting is not elected, the changes in the fair value of unsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates, including a discussion regarding the estimation uncertainty and the impact that our critical accounting estimates have had, or are reasonably likely to have, on our financial condition or results of operations, are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves, fair value estimates, revenue recognition and contingencies and insurance accounting. These estimates, in our opinion, are subjective in nature, require the use of professional judgment and involve complex analysis.
When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.
Results of Operations
The results of operations for the three months ended March 31, 2026 and 2025 have been derived from our unaudited condensed consolidated financial statements.
Factors Affecting the Comparability of the Historical Financial Results
● The sale of our non-operated Eagle Ford assets in July 2025 for $23.0 million, excluding $1.9 million of final post-closing adjustments, resulting in a final adjusted purchase price of $21.1 million.
● The sale of all of our assets located in East Texas/North Louisiana in December 2025 for $122.0 million, subject to estimated post-closing adjustments.
● The sale of all of our assets located in Oklahoma in December 2025 for $92.5 million, subject to estimated post-closing adjustments.
● Other sales of interest in certain units with rights in the Cotton Valley and Haynesville basins during 2025 for $13.6 million.
As a result of the factors listed above, the historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.
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The following table summarizes certain of the results of operations for the periods indicated.
For the Three Months Ended
March 31,
2026
2025
($ In thousands except per unit amounts)
Oil and natural gas sales
$
37,263
$
70,341
Other revenues
201
1,709
Lease operating expense
22,154
37,417
Gathering, processing and transportation
759
4,286
Taxes other than income
2,340
4,384
Depreciation, depletion and amortization
5,660
8,494
General and administrative expense
8,913
10,815
Loss (gain) on commodity derivative instruments
45,822
14,317
Pipeline incident loss
12
396
(Gain) loss on sale of properties
(164)
(6,251)
Interest expense, net
988
3,519
Income tax (expense) benefit - current
—
(1)
Income tax (expense) benefit - deferred
11,558
1,538
Net income (loss)
(38,116)
(5,861)
Oil and natural gas revenues:
Oil sales
$
37,408
$
49,982
NGL sales
(93)
6,157
Natural gas sales
(52)
14,202
Total oil and natural gas revenues
$
37,263
$
70,341
Production volumes:
Oil (MBbls)
576
737
NGLs (MBbls)
2
263
Natural gas (MMcf)
7
3,647
Total (MBoe)
580
1,607
Average net production (MBoe/d)
6.4
17.9
Average realized sales price (excluding commodity derivatives):
Oil (per Bbl)
$
64.93
$
67.82
NGL (per Bbl) (1)
(37.36)
23.46
Natural gas (per Mcf) (1)
(6.93)
3.89
Total (per Boe)
$
64.26
$
43.76
Average unit costs per Boe:
Lease operating expense
$
38.20
$
23.28
Gathering, processing and transportation
1.31
2.67
Taxes other than income
4.03
2.73
General and administrative expense
15.37
6.73
Depletion, depreciation and amortization
9.76
5.29
(1)
The average realized sales price for the three months ended March 31, 2026, was negatively impacted by post-divestiture accrual estimate adjustments related to the Company’s East Texas and Oklahoma assets sales completed during the fourth quarter of 2025.
For the Three Months Ended March 31, 2026 Compared to the Three Months Ended March 31, 2025
We reported a net loss of $38.1 million compared to a net loss of $5.9 million for the three months ended March 31, 2026 and 2025, respectively.
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Oil, natural gas and NGL revenues were $37.3 million and $70.3 million for the three months ended March 31, 2026 and 2025, respectively. Average net production volumes were approximately 6.4 MBoe/d and 17.9 MBoe/d for the three months ended March 31, 2026 and 2025, respectively. The average realized sales prices were $64.26 per Boe and $43.76 per Boe for the three months ended March 31, 2026 and 2025, respectively. The decrease of $33.0 million in oil, natural gas and NGL revenue was primarily driven by the divestiture of our East Texas, Oklahoma and our non-operated Eagle Ford assets in 2025. Oil revenues for our Beta and Bairoil assets were $37.4 million and $39.9 million for the three months ended March 31, 2026 and 2025, respectively. The change in oil revenue at Beta and Bairoil was primarily due to lower realized oil commodity prices.
Other revenues were $0.2 million and $1.7 million for the three months ended March 31, 2026 and 2025, respectively. The decrease of $1.5 million in other revenue was primarily driven by the divestiture of our East Texas, Oklahoma and our non-operated Eagle Ford assets in 2025. For the three months ended March 31, 2026, other revenues primarily consisted of $0.1 million for pipeline transportation income. For the three months ended March 31, 2025, other revenues consisted of service revenues of $0.9 million with respect to our wholly owned subsidiary, Magnify Energy Services, and iodine sales of $0.7 million.
Lease operating expenses were $22.2 million and $37.4 million for the three months ended March 31, 2026 and 2025, respectively. On a per Boe basis, lease operating expenses were $38.20 and $23.28 for the three months ended March 31, 2026 and 2025, respectively. The decrease of $15.2 million in lease operating expense was primarily driven by the divestiture of our East Texas, Oklahoma and our non-operated Eagle Ford assets in 2025. Lease operating expenses for Beta and Bairoil were $22.0 million and $27.0 million for the three months ended March 31, 2026 and 2025, respectively. The decrease in lease operating expenses at Beta and Bairoil was primarily driven by lower CO 2 costs and electricity at Bairoil and lower base costs at Beta.
Gathering, processing and transportation expenses were $0.8 million and $4.3 million for the three months ended March 31, 2026 and 2025, respectively. On a per Boe basis, gathering, processing and transportation expenses were $1.31 and $2.67 for the three months ended March 31, 2026 and 2025, respectively. The decrease of $3.5 million in gathering, processing and transportation expenses was primarily driven by the divestiture of our East Texas, Oklahoma and our non-operated Eagle Ford assets in 2025. Gathering, processing and transportation expenses for Beta were $0.7 million and $0.6 million for the three months ended March 31, 2026 and 2025, respectively.
Taxes other than income were $2.3 million and $4.4 million for the three months ended March 31, 2026 and 2025, respectively. On a per Boe basis, taxes other than income were $4.03 and $2.73 for the three months ended March 31, 2026 and 2025, respectively. The decrease of $2.0 million in taxes other than income was primarily driven by the divestiture of our East Texas, Oklahoma and our non-operated Eagle Ford assets in 2025. Taxes other than income at Beta and Bairoil were $2.3 million and $3.0 million for the three months ended March 31, 2026 and 2025, respectively. The decrease in taxes other than income was primarily driven by lower production taxes and lower NOx credits purchased.
Depreciation, depletion & amortization (“DD&A”) expenses were $5.7 million and $8.5 million for the three months ended March 31, 2026 and 2025, respectively. The decrease of $2.8 million in DD&A expense was primarily driven by the divestiture of our East Texas, Oklahoma and our non-operated Eagle Ford assets in 2025. DD&A expenses for Beta and Bairoil were $5.6 million and $4.0 million for the three months ended March 31, 2026 and 2025, respectively.
General and administrative expenses were $8.9 million and $10.8 million for the three months ended March 31, 2026 and 2025, respectively. The change in general and administrative expenses was primarily related to (i) a decrease of $1.6 million in acquisition and divestiture costs; (ii) a decrease of $0.5 million for salaries and other payroll benefits, (iii) a decrease of $0.1 million in legal expense, partially offset by (i) an increase of $0.3 million in severance expense, (ii) an increase of $0.6 million due to the elimination of COPAS overhead charges and (iii) an increase of $0.2 million in stock compensation expense. In addition, general and administrative expenses for the three months ended March 31, 2026 included a credit of $0.5 million for the management fees received for the transition services related to the divestiture of our East Texas and Oklahoma assets.
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Acquisition and divestiture related expenses included the following for the periods indicated below (in thousands):
For the Three Months Ended
March 31,
2026
2025
Cost incurred related to the contemplated merger with Juniper Capital
$
—
$
1,591
Cost incurred related to the East Texas and Oklahoma divestitures
73
—
Other acquisition and divestitures expenses
—
38
$
73
$
1,629
Net loss (gain) on commodity derivative instruments of $45.8 million was recognized for the three months ended March 31, 2026, consisting of a $43.4 million decrease in the fair value of open positions and $2.6 million of cash settlements paid on expired positions, partially offset by $0.2 million of cash settlement received on terminated derivative instruments. Net loss on commodity derivative instruments of $14.3 million was recognized for the three months ended March 31, 2025, consisting of a $14.8 million decrease in the fair value of open positions, partially offset by $0.5 million of cash settlements received on expired positions.
Pipeline incident loss was less than $0.1 million and $0.4 million for the three months ended March 31, 2026 and 2025, respectively. The costs reflect certain expenses not expected to be recovered under an insurance policy. See Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Gain on sale of properties was $0.2 million and $6.3 million for the three months ended March 31, 2026 and 2025. See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.
Interest expense, net was $1.0 million for the three months ended March 31, 2026 and $3.5 million for the three months ended March 31, 2025. The change was primarily related to the Company paying off all outstanding debt as of December 31, 2025. In 2026, the Company will continue to have interest expense associated with its surety bonds.
Current income tax benefit (expense) was $0.0 million and was less than ($0.1) million for the three months ended March 31, 2026 and 2025, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Deferred income tax benefit (expense) was $11.6 million and $1.5 million for the three months ended March 31, 2026 and 2025, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Non-GAAP Financial Measures
We include in this report the non-GAAP financial measure of Adjusted Net Income (Loss) and Adjusted EBITDA and provide our reconciliation of net income (loss) to Adjusted Net Income (Loss), Adjusted EBITDA to net income (loss), and net cash flows from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP.
Adjusted Net Income (Loss)
We define Adjusted Net Income (Loss) as net income (loss) adjusted for unrealized loss (gain) on commodity derivative instruments, acquisition and divestiture-related expenses, impairment expense, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our federal statutory tax rate. This measure is not meant to disassociate these items from management’s performance but rather is intended to provide helpful information to investors interested in comparing our performance between periods. Adjusted Net Income (Loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP.
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The following tables present our reconciliation of the Company’s net income (loss) to Adjusted Net Income (Loss), our most directly comparable GAAP financial measures, for each of the periods indicated.
For the Three Months Ended
March 31,
2026
2025
(In thousands)
Net (loss) income
$
(38,116)
$
(5,861)
Unrealized loss (gain) on commodity derivative instruments
43,448
14,820
Acquisition and divestiture-related expenses
73
1,629
Non-recurring costs:
(Gain) loss on sale of properties
(164)
(6,251)
Tax effect of adjustments (1)
19
971
Adjusted net income (loss)
$
5,260
$
5,308
(1) The federal statutory rates were utilized for all periods presented.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss):
Plus:
● Interest expense;
● Income tax expense;
● DD&A;
● Impairment of goodwill and long-lived assets (including oil and natural gas properties);
● Accretion of AROs;
● Loss on commodity derivative instruments;
● Cash settlements received on expired commodity derivative instruments;
● Amortization of gain associated with terminated commodity derivatives;
● Losses on sale of assets;
● Share-based compensation expenses;
● Exploration costs;
● Acquisition and divestiture related expenses;
● Reorganization items, net;
● Severance payments; and
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● Other non-routine items that we deem appropriate.
Less:
● Interest income;
● Income tax benefit;
● Gain on commodity derivative instruments;
● Cash settlements paid on expired commodity derivative instruments;
● Gains on sale of assets and other, net; and
● Other non-routine items that we deem appropriate.
We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.
Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. 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 the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.
In addition, we use Adjusted EBITDA as an additional measure to evaluate actual cash flow available to develop existing reserves or acquire additional oil and natural gas properties.
The following tables present our reconciliation of the Company’s net income (loss) to Adjusted EBITDA and cash flows from operating activities to Adjusted EBITDA, our most directly comparable GAAP financial measures, for each of the periods indicated.
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Reconciliation of Net Income (Loss) to Adjusted EBITDA
For the Three Months Ended
March 31,
2026
2025
(In thousands)
Net income (loss)
$
(38,116)
$
(5,861)
Interest expense, net
988
3,519
Income tax expense (benefit) - current
—
1
Income tax expense (benefit) - deferred
(11,558)
(1,538)
DD&A
5,660
8,494
Accretion of AROs
1,248
2,183
Loss (gain) on commodity derivative instruments
45,822
14,317
Cash settlements (paid) received on expired commodity derivative instruments
(2,554)
503
(Gain) loss on sale of properties
(164)
(6,251)
Share-based compensation expense
2,056
1,890
Acquisition and divestiture related expenses
73
1,629
Severance payments
320
—
Amortization of gain associated with terminated commodity derivatives
(250)
159
Pipeline incident loss
12
396
Loss on settlement of AROs
30
(3)
Exploration costs
—
6
Other
204
—
Adjusted EBITDA
$
3,771
$
19,444
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
For the Three Months Ended
March 31,
2026
2025
(In thousands)
Net cash provided by operating activities
$
4,474
$
25,501
Changes in working capital
(2,350)
(5,372)
Interest expense, net
988
3,519
(Gain) loss on sale of property
—
(6,251)
Acquisition and divestiture related expenses
73
1,629
Pipeline incident loss
12
396
Severance payments
320
—
Plugging and abandonment cost
30
171
Amortization and write-off of deferred financing fees
(80)
(315)
Cash settlements paid (received) on terminated derivatives
350
—
Amortization of gain associated with terminated commodity derivatives
(250)
159
Income tax expense (benefit) - current
—
1
Exploration costs
—
6
Other
204
—
Adjusted EBITDA
$
3,771
$
19,444
Liquidity and Capital Resources
Overview. The divestitures reduced our ongoing capital requirements and streamlined our operating profile, which we believe positions us with greater financial flexibility. Following the payoff of the debt facility, we no longer have any outstanding borrowings.
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Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our Revolving Credit Facility, equity and debt capital markets and proceed from the sale of assets. However, future cash flows are subject to a number of variables, including the level of our oil and NGL production and the prices we receive for our oil production, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. We anticipate funding our 2026 capital program from cash on hand and internally generated cash flow but retain the flexibility to utilize borrowings under debt facilities available to us, and/or to access the debt and equity capital markets. As we pursue reserve and production growth, we plan to monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements.
Based on our current oil price expectations, we believe existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our Revolving Credit Facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter.
Capital Markets. We do not currently anticipate any near-term capital markets activity, but we will continue to evaluate the availability of public debt and equity for funding capital needs.
Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil and NGL prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 25% - 75%, depending on availability under the Revolving Credit Facility, of our estimated production from total proved developed producing reserves over a one-year period at any given point of time. We may, however, from time to time, hedge more or less than this approximate amount. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. Market conditions may also impact our ability to enter into future commodity derivative contracts.
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil to a small number of purchasers. Non-performance by a customer could also result in a loss.
Capital Expenditures. Our total capital expenditures were approximately $21.0 million for the three months ended March 31, 2026, which were primarily related to the development program at Beta.
Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable, as well as the classification of our debt outstanding. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. From time-to-time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual.
As of March 31, 2026, we had working capital (excluding commodity derivatives) of $34.6 million primarily from cash on hand of $41.5 million, accounts receivable of $19.9 million and prepaid expenses of $23.9 million partially offset by accrued liabilities of $20.7 million, revenues payable of $7.5 million, and accounts payable of $22.5 million.
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Debt Agreement
Revolving Credit Facility. On December 31, 2025, we amended the Revolving Credit Facility with Citizens Bank, as administrative agent. As of March 31, 2026, the borrowing base under the facility was $25.0 million with elected commitments of $15.0 million. At March 31, 2026, the Company had no loans outstanding under the Revolving Credit Facility.
As of March 31, 2026, we had approximately $15.0 million of available borrowings under our Revolving Credit Facility.
As of March 31, 2026, we were in compliance with all the financial covenants (current ratio and total leverage ratio) and non-financial covenants associated with the Revolving Credit Facility.
For additional information regarding our Revolving Credit Facility, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Material Cash Requirements
Contractual Commitments. We have contractual commitments under our debt agreements, including interest payments and principal payments. See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Lease Obligations . We have operating leases for office and warehouse spaces, office equipment, compressors and surface rentals related to our business obligations. See Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Sinking Fund Payments . We have a funding requirement to fund two trust accounts to comply with supplemental regulatory bonding requirements related to our decommissioning obligations for the Beta production facilities. As of March 31, 2026, our future commitments under these agreements were $6.8 million for the remainder of 2026 and $9.0 million per year until the escrow accounts are fully funded. See Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the three months ended March 31, 2026 and 2025 have been derived from our Unaudited Condensed Consolidated Financial Statements. As a result of the divestiture activity in 2025, the period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results. For information regarding the individual components of our cash flow amounts, see our Unaudited Condensed Consolidated Statements of Cash Flows included under “Item 1. Financial Statements” of this quarterly report.
For the Three Months Ended
March 31,
2026
2025
(In thousands)
Net cash provided by operating activities
$
4,474
$
25,501
Net cash used in investing activities
(21,558)
(21,497)
Net cash used in financing activities
(2,096)
(4,004)
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $4.5 million and $25.5 million for the three months ended March 31, 2026 and 2025, respectively.
Production volumes were approximately 6.4 MBoe/d and 17.9 MBoe/d for the three months ended March 31, 2026 and 2025, respectively. The average realized sales price was $64.26 per Boe and $43.76 per Boe for the three months ended March 31, 2026 and 2025, respectively.
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Net cash provided by operating activities for the three months ended March 31, 2026 included $2.6 million of cash paid on expired commodity derivative instruments compared to $0.5 million of cash received on expired commodity derivatives for the three months ended March 31, 2025. For the three months ended March 31, 2026, we had a net loss on commodity derivative instruments of $45.8 million compared to a net loss on commodity derivative instruments of $14.3 million for the three months ended March 31, 2025.
Investing Activities. Net cash used in investing activities for the three months ended March 31, 2026 was $21.6 million, of which $19.0 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the three months ended March 31, 2025 was $21.5 million. Additions to oil and natural gas properties were $24.9 million for the three months ended March 31, 2025 and $0.3 million for additions to other property and equipment for the three months ended March 31, 2025.
In January 2025, we purchased and sold certain rights, title and interest in assets in East Texas to a third party, whereby we received net proceeds of $6.3 million. See additional information discussed in Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our Beta properties. Additions to restricted investments were $2.5 million for the three months ended March 31, 2026 and 2025, respectively.
Financing Activities . Shares withheld for taxes were $2.1 million and $2.0 million for the three months ended March 31, 2026 and 2025, respectively. The Company had no debt outstanding for the three months ended March 31, 2026. For the three months ended March 31, 2025 we had net repayments of $2.0 million related to our Revolving Credit Facility.
Off–Balance Sheet Arrangements
As of March 31, 2026, we had no off–balance sheet arrangements.
Recently Issued Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
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