ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis (“MD&A”) of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” contained herein. 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. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I, Item 1A. of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of this Annual 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.
Our 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). During 2025, we completed several divestiture transactions, including the sale of our non-operated Eagle Ford assets in July 2025, our East Texas/North Louisiana assets in December 2025 and our Oklahoma assets in December 2025. As of the date of this Annual Report, our remaining properties consist solely of Bairoil and Beta.
Production and Operation Update
Total production for the Company in 2025 was composed of approximately 45% oil, 39% natural gas and 16% NGLs compared to 43% oil, 39% natural gas and 18% NGLs in 2024. The change in our oil production was primarily related to the development of wells at Beta. We had a decrease of 10% in oil and natural gas sales primarily due to lower volumes and decrease in oil prices. Average realized sales price per Boe was $38.03 for 2025 compared to $39.61 for 2024.
Our estimated proved reserves decreased to 38.1 MMBoe in 2025 compared to 93.0 MMBoe in 2024. The decrease was primarily due to 53.2 MMBoe for divestitures reserves. In addition, the change in reserves were impacted by changes in commodity prices, partially offset by upward reserves revisions due to performance, and reserve additions due to new locations specifically related to Beta.
As of December 31, 2025, we are the operator of record for properties containing 100% of our total estimated proved reserves.
Recent Developments
Reduction in Force
During the fourth quarter of 2025 and throughout the first quarter of 2026, certain employees were impacted by a workforce reduction resulting in the involuntary termination of 36 employees across the Company. The Company recorded $6.8 million of severance expense for the year ended December 31, 2025, which is included in “general and administrative expense” in the Company’s Consolidated Statement of Operations.
Amended Revolving Credit Facility
On December 31, 2025, OLLC entered into the Borrowing Base Redetermination, Commitment Increase and Second Amendment to Amended and Restated Credit Agreement (the “Second Amendment”), among OLLC, Amplify Acquisitionco LLC, the guarantors party thereto, the lenders party thereto and Citizens Bank, N.A., as administrative agent for the lenders. The Second Amendment amends the Amended and Restated Credit Agreement, dated July 31, 2023 (as amended, the “Credit Agreement”), to, among other things: (i) set the Borrowing Base to $25.0 million, with elected commitments of $15.0 million and (ii) extend the maturity date under the Credit Agreement to December 31, 2028. We had no amounts outstanding at December 31, 2025.
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Revolution Purchase and Sale Agreement
On November 4, 2025, Amplify Oklahoma Operating LLC, a Delaware limited liability company and indirect, wholly owned subsidiary of the Company (“Amplify Oklahoma”), Magnify Energy Services LLC, a Delaware limited liability company and indirect, wholly owned subsidiary of the Company (“Magnify” and, together with Amplify Oklahoma, the “Revolution Sellers”) and OLLC, for certain limited purposes, entered into a purchase and sale agreement (the “Revolution Purchase and Sale Agreement”) with Revolution Resources III, LLC, a Delaware limited liability company (“Revolution”), pursuant to which the Revolution Sellers sold to Revolution certain assets of the Revolution Sellers, which include, among other things, the Revolution Sellers’ right, title and interest in and to certain specified oil and gas properties and equipment within or related to certain designated lands in Oklahoma (the “Revolution Asset Sale”) for a cash purchase price of $92.5 million, subject to estimated post-closing adjustments under the Revolution Purchase and Sale Agreement. The Revolution Asset Sale closed on December 29, 2025, with an effective date of October 1, 2025. We received net proceeds of $88.7 million from the Revolution Asset Sale. The proceeds from the divestiture were used to reduce borrowings under our Revolving Credit Facility. In connection with this transaction, we performed an assessment of the fair value of the net book value and determined that the assets were , and as such, we recorded expense of $34.0 million to write down those assets to the estimated purchase price less cost to sell.
EQV Purchase and Sale Agreement
On October 28, 2025, OLLC and Magnify (together with OLLC, the “EQV Sellers”), entered into a purchase and sale agreement (as subsequently amended, the “EQV Purchase and Sale Agreement”) with EQV Alpha LLC, a Delaware limited liability company (“Alpha”), pursuant to which the EQV Sellers sold to Alpha certain assets of the EQV Sellers, which include, among other things, the EQV Sellers’ right, title and interest in and to certain specified oil and gas properties and equipment within or related to certain designated lands in East Texas and Louisiana (the “EQV Asset Sale”) for a cash purchase price of $122.0 million, subject to estimated post-closing adjustments under the EQV Purchase and Sale Agreement. The EQV Asset Sale closed on December 23, 2025, with an effective date of October 1, 2025. We received net proceeds of $111.6 million from the EQV Asset Sale. The proceeds from the divestiture were used to reduce borrowings under our Revolving Credit Facility.
East Texas Haynesville Monetization
On October 2, 2025, the Company entered into a purchase and sale agreement to sell its remaining interest in certain units with rights in the Cotton Valley and Haynesville basins in Harrison County, Texas, generating $5.3 million in net proceeds from the transactions. The sale closed on October 24, 2025, with an effective date of October 1, 2025.
Other 2025 Developments
Other 2025 Divestitures
In July 2025, we closed a transaction to divest our non-operated Eagle Ford assets for a total purchase price of $23.0 million, excluding $1.9 million of final post-closing adjustments, resulting in a final adjusted purchase price of $21.1 million. In connection with this transaction, we performed an assessment of the fair value of the net book value and determined that the assets were impaired, and as such, we recorded impairment expense of $8.4 million to write down those assets to the estimated purchase price less cost to sell.
Throughout 2025, we had other divestitures where we sold certain rights and interests in the Cotton Valley and Haynesville basins generating approximately $7.8 million in net proceeds from such transactions.
Leadership Changes
On July 21, 2025, the Company, and Mr. Martyn Willsher, the Company’s former President, Chief Executive Officer and member of the Company’s board of directors (the “Board”), agreed that (i) Mr. Willsher’s roles as President and Chief Executive Officer of the Company and a member of the Board terminated effective July 22, 2025 (the “Transition Date”), and (ii) Mr. Willsher assumed the non-executive employee role of Special Advisor to the Company on the Transition Date.
In connection with the transition of Mr. Willsher’s role, the Company and Mr. Willsher entered into a Transition and Separation Agreement (the “Transition Agreement”), effective as of the Transition Date. Pursuant to the terms of the Transition Agreement, Mr. Willsher served as Special Advisor to the Company until December 31, 2025.
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Appointment of Chief Executive Officer and Director
On July 21, 2025, the Board appointed Mr. Daniel Furbee, previously the Company’s Senior Vice President and Chief Operating Officer, to Chief Executive Officer and as a member of the Board, effective as of the Transition Date. In connection with Mr. Furbee’s appointment as Chief Executive Officer, Mr. Furbee and the Company entered into a performance-based restricted stock units award agreement.
Appointment of President and Chief Financial Officer
On July 21, 2025, the Board appointed Mr. James Frew, previously the Company’s Senior Vice President and Chief Financial Officer, to President and Chief Financial Officer, effective as of the Transition Date.
Appointment of Vice President and Chief Accounting Officer
On November 14, 2025, Mr. Eric Dulany and the Company mutually agreed Mr. Dulany’s tenure as Vice President and Chief Accounting Officer would end, effective immediately. Mr. Dulany’s departure did not result from any disagreement with the Company, the Company’s management or the Board. On November 14, 2025, the Board appointed Ms. Natasha France, to serve as Vice President and Chief Accounting Officer of the Company, effective immediately.
Termination of Contemplated Merger with Juniper Capital
On January 14, 2025, the Company entered into an Agreement and Plan of Merger, as subsequently amended (the “Merger Agreement”) with Amplify DJ Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of the Company (“First Merger Sub”), Amplify PRB Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of Amplify Energy (“Second Merger Sub”), North Peak Oil & Gas, LLC, a Delaware limited liability company (“NPOG”), Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company (“COG” and, together with NPOG, the “Acquired Companies”), and, solely for the limited purposes set forth in the Merger Agreement, Juniper Capital Advisors, L.P. (“Juniper Capital”) and the Specified Company Entities set forth on Annex A thereto, pursuant to which, at the effective time of the Contemplated Mergers (as defined below), it was contemplated that (i) NPOG would merge with and into First Merger Sub, with NPOG surviving the merger as an indirect, wholly owned subsidiary of the Company and (ii) COG would merge with and into Second Merger Sub, with COG surviving the merger as an indirect, wholly owned subsidiary of the Company, in each case, subject to the terms and conditions of the Merger Agreement (clauses (i) and (ii), together, the “Contemplated Mergers”).
On April 25, 2025, pursuant to Section 8.1(a) of the Merger Agreement, the Company and the Acquired Companies entered into a mutual termination agreement (the “Termination Agreement”) to terminate the Merger Agreement (the “Termination”), effective immediately. As a result of the Termination Agreement, the Merger Agreement is of no further force and effect.
Industry Trends
For a discussion of how industry trends have affected and may continue to affect our business and financial condition, see the discussion under the heading “Industry Trends” in Part I, Item 1 of this report, as well as the Risk Factors set forth in Part I, Item 1A of this report.
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.
Production Volumes
Production volumes directly impact our results of operations. For more information about our volumes, see “— Results of Operations” below.
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Realized Prices on the Sale of Oil and Natural Gas
We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, realized prices are heavily influenced by product quality and location relative to consuming and refining markets.
Natural Gas . The NYMEX-Henry Hub future price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas can differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO 2 and other inert content by volume. Natural gas with a high Btu content (“wet” natural gas) sells at a premium to natural gas with low Btu content (“dry” natural gas) because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO 2 content sells at a premium to natural gas with high sulfur and CO 2 content because of the added cost required to separate the sulfur and CO 2 from the natural gas to render it marketable. Wet natural gas may be processed in third-party natural gas plants, where residue natural gas as well as NGLs are recovered and sold. At the wellhead, our natural gas production typically has an average energy content greater than 1,000 Btu. The dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.
Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the produced natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Historically, these index prices have generally been at a discount to NYMEX-Henry Hub natural gas prices.
Oil . The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The ICE Brent futures price is a widely used global price benchmark for oil. The actual prices realized from the sale of oil can differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s API gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil).
Location differentials result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential).
The oil produced from our onshore properties is a combination of sweet and sour oil, which varies by location. This oil is typically sold at the NYMEX-WTI price, adjusted for quality and transportation differential, depending primarily on location and purchaser. The oil produced from our offshore properties is heavy and sour oil and was sold based on refiners’ posted prices for ICE Brent for the year ended December 31, 2025.
Price Volatility . In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. The following table shows the low and high commodity future index prices for the periods indicated:
High
Low
For the Year Ended December 31, 2025:
NYMEX-WTI oil future price range per Bbl
NYMEX-Henry Hub natural gas future price range per MMBtu
ICE Brent oil future price range per Bbl
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Commodity Derivative Contracts . Our hedging activities are intended to support oil, natural gas and NGL prices at targeted levels and to manage our exposure to commodity price fluctuations. The covenants in our Revolving Credit Facility require us 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 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 range. 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. The current market conditions may also impact our ability to enter into future commodity derivative contracts.
Principal Components of Cost Structure
Lease operating expense . These are the day-to-day costs incurred to maintain production of our oil, natural gas, and NGLs. Such costs include utilities, direct labor, water injection and disposal, the cost of CO 2 injection, chemicals, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services and activities performed during a specific period.
Gathering, processing and transportation. These are costs incurred to deliver production of our oil, natural gas, and NGLs to the market. Cost levels of these expenses can vary based on the volume of oil, natural gas, and NGLs production.
Taxes other than income . These consist of production, ad valorem, NOx credits, and franchise taxes. Production taxes are paid on produced oil, natural gas, and NGLs based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take advantage of credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties. Franchise taxes are privilege taxes levied by states that are imposed on companies, including limited liability companies and partnerships, which gives the businesses the right to be chartered or operate within that state.
Depreciation, depletion and amortization . Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop oil and natural gas properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.
Impairment expense. Proved properties are impaired whenever the net carrying value of the properties exceed their estimated undiscounted future cash flows. Unproved properties are impaired based on time or geologic factors.
General and administrative expense . These costs include overhead, including payroll and benefits for certain employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expenses associated with certain long-term incentive-based plans, audit and other professional fees and legal compliance expenses.
Interest expense, net. Historically, we have financed a portion of our working capital requirements, capital development and acquisitions with borrowings under our Revolving Credit Facility. We incur interest expense that is affected by both fluctuations in interest rates and financing decisions. These costs also include capitalized interest, the amortization and write off of deferred financing costs and the amortization of surety bonds.
Income tax expense. We are a corporation subject to federal and certain state income taxes.
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Outlook
Based on our current plans, our capital expenditure program for the full year 2026 is expected to be approximately $45.0 million to $65.0 million. Our capital expenditure program for 2026 is allocated among our remaining properties with 97% allocated to Beta and 3% allocated to Bairoil. The charts below detail the allocation of capital by investment type based on the midpoint of our 2026 capital expenditure range.
2026 CAPEX by Investment
As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices and other factors. We anticipate funding our 2026 capital program from internally generated cash flow and cash on hand.
Critical Accounting Policies and Estimates
The methods, estimates and judgments we use in applying our critical accounting policies have a significant impact on the results we report in our Consolidated Financial Statements. We evaluate our estimates and judgments on an on-going basis. We base our estimates on historical experience and on assumptions that we believe to be reasonable under the circumstances. Our experience and assumptions form the basis for our judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may vary from what we anticipate and different assumptions or estimates about the future could change our reported results.
Oil and Natural Gas Properties. We use the successful efforts method of accounting for our oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense.
We review the carrying value of our oil and natural gas properties, including support equipment for impairments quarterly or when events and circumstances indicate the carrying value of our properties may not be recoverable. Such indications could be the result of downward revisions of the reserve estimates, less than expected production or drilling results, higher operating and development costs, or lower commodity prices. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.
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We believe accounting for oil and natural gas properties is a critical accounting estimate because the policies discussed above impact the carrying value of our properties and involve significant judgments about the impact of future events on our estimated cash flows. Future events and circumstances currently unknown to us could require future impairments to our properties and materially change the carrying value of our properties.
Oil and Natural Gas Reserves . Proved oil and natural gas reserves are estimated in accordance with the rules established by the SEC and FASB. The rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalation in future years except by contractual arrangements. Our reserve estimates are prepared by our reserve engineers and audited by independent engineers.
Our reserve estimates are updated at least annually using geological and reserve data, as well as production performance data. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates, while decreases in recoverable economic volumes generally increase per unit depletion rates. A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimate may impact the outcome of our assessment of oil and natural gas producing properties for impairment. We cannot predict what reserve revisions may be required in future periods.
We believe the estimate of oil and natural gas reserves is a critical accounting estimate because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations for any period could be materially affected by changes in our assumptions. Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense.
Derivative Financial Instruments. Our commodity derivative financial instruments are used to reduce the impact of oil and natural gas price fluctuations. We record our derivative instrument in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings as we have not elected hedge accounting for any of our derivative positions. Significant changes to the market value of derivative instruments due to the volatility of oil and natural gas prices can have an impact on our financial condition and results of operations.
Contingencies Accounting. A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. Although we are insured against various risks to the extent we believe is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.
Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.
We believe contingencies accounting is a critical accounting estimate because we must assess the probability of the loss related to the contingency.
Income Tax. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards.
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In assessing the carrying value of our net deferred tax assets, we consider the realizability of our deferred tax assets each reporting period. The realization of any deferred tax asset is dependent upon the generation of future taxable income sufficient to demonstrate our ability to utilize the deferred tax asset in the period in which the temporary differences become deductible or in a future period prior to expiration. We considered all available evidence, including cumulative historical losses (defined as pre-tax earnings as adjusted for permanent tax adjustment), scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could significantly impact the amounts provided for income taxes in our Consolidated Financial Statements.
We believe accounting for income taxes is a critical accounting estimate because the policies discussed above in assessing the carrying value of our net deferred tax assets require estimates and judgements about the impact of future events on our projected taxable income, the results of which can have a material impact on our Consolidated Financial Statements.
In future periods, we may demonstrate cumulative historical losses for the previous three fiscal years, which could significantly impact our need for a valuation allowance. Any increase in the valuation allowance would increase our income tax expense in the Consolidated Statements of Operations.
Results of Operations
The results of operations for the years ended December 31, 2025 and 2024 have been derived from our 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 $13.6 million.
As a result of the factors listed above, the historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.
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The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.
For the Year Ended
December 31,
($ In thousands)
Oil and natural gas sales
Other revenues
Lease operating expense
Gathering, processing and transportation
Taxes other than income
Depreciation, depletion and amortization
Impairment expense
General and administrative expense
Loss (gain) on commodity derivative instruments
Pipeline incident loss
(Gain) loss on sale of properties
Interest expense, net
Income tax (expense) benefit - current
Income tax (expense) benefit - deferred
Net income (loss)
Oil and natural gas revenues:
Oil sales
NGL sales
Natural gas sales
Total oil and natural gas revenues
Production volumes:
Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total (MBoe)
Average net production (MBoe/d)
Average realized sales price (excluding commodity derivatives):
Oil (per Bbl)
NGL (per Bbl)
Natural gas (per Mcf)
Total (per Boe)
Average unit costs per Boe:
Lease operating expense
Gathering, processing and transportation
Taxes other than income
General and administrative expense
Depletion, depreciation and amortization
For the year ended December 31, 2025 compared to the year ended December 31, 2024
Net income of $44.0 million compared to net income of $12.9 million was recorded for the year ended December 31, 2025 and 2024, respectively.
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Oil, natural gas and NGL revenues were $256.1 million and $283.0 million for the year ended December 31, 2025 and 2024, respectively. Average net production volumes were approximately 18.4 MBoe/d and 19.5 MBoe/d for the year ended December 31, 2025 and 2024, respectively. The average realized sales price was $38.03 per Boe and $39.61 per Boe for the year ended December 31, 2025 and 2024, respectively. The change in average realized sales price was due to lower realized sales prices for oil, partially offset by higher realized sales prices for natural gas.
Other revenues were $7.3 million and $11.7 million for the year ended December 31, 2025 and 2024, respectively. For the year ended December 31, 2025, other revenues consisted of iodine sales of $2.7 million and service revenues of $4.1 million with respect to our wholly owned subsidiary, Magnify Energy Services (“Magnify”). For the year ended December 31, 2024, other revenues consisted of iodine sales of $2.4 million, and service revenues of $3.1 million for Magnify. Additionally, for the year ended December 31, 2024, we recorded a revenue suspense release of $4.8 million.
Lease operating expense was $141.3 million and $143.0 million for the year ended December 31, 2025 and 2024, respectively. The change in lease operating expense was primarily due to the divestiture of our non-operated Eagle Ford assets and lower electricity and CO 2 costs at Bairoil starting in the fourth quarter, partially offset by increased workover expense at Beta. On a per Boe basis, lease operating expense was $20.99 and $20.01 for the year ended December 31, 2025 and 2024, respectively.
Gathering, processing and transportation expenses were $17.8 million and $18.4 million for the year ended December 31, 2025 and 2024, respectively. On a per Boe basis, gathering, processing and transportation expenses were $2.64 and $2.58 for the year ended December 31, 2025 and 2024, respectively. The decrease in gathering, processing and transportation expense was primarily driven by lower volumes.
Taxes other than income were $15.9 million and $20.9 million for the year ended December 31, 2025 and 2024, respectively. On a per Boe basis, taxes other than income were $2.36 and $2.92 for the year ended December 31, 2025 and 2024, respectively. The change in taxes other than income was primarily related to a reduction in production taxes due to lower volumes, the divestiture of our non-operated Eagle Ford assets, lower year-over-year revenues and a decrease in waste emission charges.
DD&A expense was $32.5 million and $32.6 million for the year ended December 31, 2025 and 2024, respectively.
General and administrative expense was $52.1 million and $35.9 million for the year ended December 31, 2025 and 2024, respectively. The change in general and administrative expense is primarily related to (i) an increase of $8.3 million in acquisition and divestiture costs, (ii) an increase of $1.5 million in stock compensation expense; (iii) an increase of $1.1 million in bad debt expense, (iv) an increase of $6.4 million in severance expense and (v) an increase of $0.9 million in legal expense; partially offset by (i) a decrease of $1.0 million in salaries and other payroll benefits, and (ii) a decrease of $0.3 million in professional services.
Acquisition and divestiture related expenses included in general and administrative expenses included the following for the periods indicated below (in thousands):
For the Year Ended
December 31,
Cost incurred related to the contemplated merger with Juniper Capital
Cost incurred related to the EQV Asset Sale and the Revolution Asset Sale
Other acquisition and divestitures expenses
Net loss (gain) on commodity derivative instruments for the year ended December 31, 2025 was a gain of $28.4 million which consisted of a $12.2 million increase in the fair value of open positions and $16.8 million in cash settlements received on expired positions, partially offset by $0.6 million in cash settlements paid on terminated derivative instruments. Net losses on commodity derivative instruments of $2.0 million were recognized for the year ended December 31, 2024, and consisted of a $20.5 million decrease in the fair value of open positions, partially offset by $0.8 million of cash settlements received on terminated derivative instruments and $17.6 million in cash settlements received on expired positions.
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Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.
Pipeline incident loss was $2.4 million and $3.9 million for the year ended December 31, 2025 and 2024. The $2.4 million reflects certain expenses not expected to be recovered under an insurance policy. See Note 17 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
(Gain) loss on sale of properties was a gain of ($99.5) million and ($1.4) million for the year ended December 31, 2025 and 2024. See additional information discussed in Note 4 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
Interest expense, net was $15.6 million and $14.6 million for the year ended December 31, 2025 and 2024, respectively. The change was primarily related to $1.5 million for write-off of deferred issuance costs.
Average outstanding borrowings under our Revolving Credit Facility were $124.9 million and $120.9 million for the year ended December 31, 2025 and 2024, respectively.
Current income tax (expense) benefit was $1.4 million and ($0.2) million for the year ended December 31, 2025 and 2024, respectively. See additional information discussed in Note 18 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
Deferred income tax benefit (expense) was ($18.2) million and ($2.2) million for the year ended December 31, 2025 and 2024, respectively. See additional information discussed in Note 18 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
For the year ended December 31, 2024 compared to the year ended December 31, 2023
Information related to the comparison of our discussion of the results of operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2024 (“ 2024 Form 10-K ”) filed with the SEC and is incorporated by reference into this Annual Report.
Non-GAAP Financial Measures
We include in this report the non-GAAP financial measures for Adjusted Net Income (Loss) and Adjusted EBITDA and provide our reconciliation of net income (loss) to Adjusted Net Income (Loss) and a reconciliation of net cash flow from operating activities to Adjusted EBITDA, our most directly comparable financial measure 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 & divestiture related expenses, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our federal statutory tax rate. Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items affecting earnings that can vary widely and unpredictably, including unrealized derivative gains and losses. 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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Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)
For the Year Ended
December 31,
(In thousands)
Net (loss) income
Unrealized loss (gain) on commodity derivative instruments
Acquisition and divestiture-related expenses
Impairment expense
Non-recurring costs:
(Gain) loss on sale of properties
Tax effect of adjustments (1)
Adjusted net income (loss)
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, including gains or losses on interest rate derivative contracts;
Income tax expense;
Impairment of goodwill and long-lived assets (including oil and natural gas properties);
Accretion of asset retirement obligations (“AROs”);
Loss on commodity derivative instruments;
Cash settlements received on expired commodity derivative instruments;
Losses on sale of assets and other, net;
Share-based compensation expenses;
Exploration costs;
Acquisition and divestiture related expenses;
Amortization of gain associated with terminated commodity derivatives;
Severance payments;
Bad debt expense; and
Other non-routine items that we deem appropriate.
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Less:
Interest income;
Income tax benefit;
Gain on expired 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 are required to comply with certain Adjusted EBITDA-related metrics under our Revolving Credit Facility.
We believe that 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 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, management uses Adjusted EBITDA to evaluate actual cash flow, develop existing reserves or acquire additional oil and natural gas properties.
The following tables present a reconciliation of the Company’s net income (loss) and cash flows 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 Year Ended
December 31,
(In thousands)
Net income (loss)
Interest expense, net
Income tax expense (benefit) - current
Income tax expense (benefit) - deferred
Impairment expense
Accretion of AROs
Loss (gain) on commodity derivative instruments
Cash settlements (paid) received on expired commodity derivative instruments
(Gain) loss on sale of properties
Share-based compensation expense
Acquisition and divestiture related expenses
Severance payments
Amortization of gain associated with terminated commodity derivatives
Pipeline incident loss
Loss on settlement of AROs
Exploration costs
Bad debt expense
Other
Adjusted EBITDA (1)
Adjusted EBITDA includes a revenue suspense release of $0.4 million and $8.4 million for the year ended December 31, 2025 and 2024, respectively.
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
For the Year Ended
December 31,
(In thousands)
Net cash provided by operating activities
Changes in working capital
Interest expense, net
(Gain) loss on sale of property
Acquisition and divestiture related expenses
Pipeline incident loss
Severance payments
Plugging and abandonment cost
Amortization and write-off of deferred financing fees
Cash settlements paid (received) on terminated derivatives
Amortization of gain associated with terminated commodity derivatives
Income tax expense (benefit) - current
Exploration costs
Other
Adjusted EBITDA (1)
Adjusted EBITDA includes a revenue suspense release of $0.4 million and $8.4 million for the year ended December 31, 2025 and 2024, respectively.
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Liquidity and Capital Resources
Overview. During the year ended December 31, 2025, we significantly enhanced our liquidity position primarily through the completion of several divestitures. Proceeds from these transactions materially strengthened our cash position and enabled us to fully repay all outstanding borrowings under our Revolving Credit Facility. As a result of these actions, we ended the year with approximately $60.7 million in cash and cash equivalents on December 31, 2025.
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.
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, and equity and debt capital markets. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas 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 our cash flows provided by operating activities and availability under our Revolving Credit Facility will provide us with the financial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2026 development activities. We believe that 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.
Termination of Contemplated Merger with Juniper Capital . In connection with the Contemplated Mergers, on April 25, 2025, pursuant to Section 8.1(a) of the Merger Agreement, the Company and the Acquired Companies entered into the Termination Agreement to terminate the Merger Agreement, effective immediately. In accordance with the terms of the Termination Agreement, the Company made a cash payment to the Acquired Companies in lieu of any termination fee which might have otherwise been payable pursuant to the Merger Agreement in the amount of $800,000 as payment for certain of the Acquired Companies’ expenses. The Company incurred professional fees and expenses of approximately $3.6 million and $1.4 million for the year ended December 31, 2025 and 2024, respectively, in connection with the Contemplated Mergers and the Termination. For additional information regarding the Termination, see Notes 4 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
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 potential future growth projects and acquisition activity.
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 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. The current 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. Non-performance by a customer could also result in losses.
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Capital Expenditures. Our total capital expenditures were approximately $82.3 million for the year ended December 31, 2025, which were primarily related to the development program at Beta and non-operated drilling and completion activities in East Texas and the Eagle Ford.
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.
As of December 31, 2025, we had working capital (excluding commodity derivatives) of $57.1 million primarily as the result of (i) a cash and cash equivalents balance of $60.7 million, (ii) an accounts receivable balance of $30.1 million and (iii) prepaid expenses and other current assets balance of $24.4 million, partially offset by (i) an accrued liabilities balance of $34.5 million, (ii) an accounts payable balance of $17.9 million, and (iii) a revenues payable balance of $5.6 million.
Debt Agreements
Revolving Credit Facility . On December 31, 2025, OLLC, as borrower, amended the Revolving Credit Facility with Citizens Bank, as administrative agent to, among other things: (i) set the Borrowing Base to $25.0 million with elected commitments of $15.0 million and (ii) extend the maturity date under the Credit Agreement to December 31, 2028. At December 31, 2025, the Company had no loans outstanding under the Revolving Credit Facility.
As of December 31, 2025, we had approximately $15.0 million of available borrowings under our Revolving Credit Facility.
As of December 31, 2025, we were in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with our Revolving Credit Facility.
For additional information regarding our Revolving Credit Facility, see Note 9 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.
Material Cash Requirements
Contractual commitments. We have contractual commitments under our debt agreements, including interest payments and principal payments. See Note 9 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual 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. As of December 31, 2025, our future commitments under these contracts were $1.4 million in 2026, $1.0 million in 2027, $0.7 million in 2028, $0.7 million in 2029 and $0.4 million thereafter. See Note 13 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.
Sinking fund payments. We have a funding requirement to fund a trust account to comply with supplemental regulatory bonding requirements related to our decommissioning obligations for our Beta production facilities. As of December 31, 2025, our future commitments under this agreement were $9.0 million per year for years 2026 through 2033. See Note 17 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.
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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 years ended December 31, 2025 and 2024, have been derived from our Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.
For the Year Ended
December 31,
(In thousands)
Net cash provided by operating activities
Net cash provided by (used in) investing activities
Net cash provided by (used in) financing activities
For the year ended December 31, 2025 compared to the year ended December 31, 2024
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes, and operating costs. Net cash provided by operating activities was $49.2 million and $51.3 million for the year ended December 31, 2025 and 2024, respectively. Production volumes decreased to 18.4 MBoe/d in 2025 from 19.5 MBoe/d in 2024, and the average realized sales price decreased to $38.03 per Boe in 2025 from $39.61 per Boe in 2024. The change in realized sales price was due to lower realized sales prices for oil, partially offset by higher realized sales prices for natural gas.
Net cash provided by operating activities for the year ended December 31, 2025 included $16.8 million of cash received on expired derivative instruments, partially offset by $0.1 million of cash payments on terminated derivatives instruments compared to $17.6 million of cash received on expired derivative instruments and $0.8 million of cash received on terminated derivatives instruments for the year ended December 31, 2024. For the year ended December 31, 2025, we had a net gain on commodity derivative instruments of $28.4 million compared to a net loss of $2.0 million for the year ended December 31, 2024.
In addition, the Company paid $2.0 million pursuant to a settlement with PHMSA. See Note 17 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
Investing Activities. Net cash provided by investing activities for the year ended December 31, 2025 was $141.3 million, of which $84.3 million was used for additions to oil and natural gas properties and $1.0 million was used for additions to other property and equipment. Net cash used in investing activities for the year ended December 31, 2024, was $82.0 million, of which $72.2 million was used for additions to oil and natural gas properties and $1.1 million used for additions to other property and equipment.
During 2025, the Company generated significant investing cash inflows from asset divestitures. These transactions included the sale of certain rights, title, and interests in East Texas assets for net proceeds of $13.6 million; the divestiture of non‑operated working interests in the Eagle Ford for net proceeds of $23.0 million; the divestiture of all our East Texas/North Louisiana assets for net proceeds of $111.6 million; and the divestiture of all our Oklahoma assets for net proceeds of $88.7 million.
For the year ended December 31, 2024, in East Texas we sold some undeveloped acreage recognizing a gain of $1.4 million.
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Beta properties. Additions to restricted investments were $10.2 million for the year ended December 31, 2025 compared to $10.1 million for the year ended December 31, 2024.
Financing Activities . We had net repayments under our Revolving Credit Facility of $127.0 million for the year ended December 31, 2025, compared to net borrowings of $12.0 million for the year ended December 31, 2024.
For the year ended December 31, 2024 compared to the year ended December 31, 2023
Information related to the comparison of our discussion of the cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023, is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” of our 2024 Form 10-K filed with the SEC and is incorporated by reference into this Annual Report.
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Capital Requirements
See “— Outlook” for additional information regarding our capital spending program for 2026.
Recently Issued Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”
