WTI 10-K & 10-Q changes, risk factors and insider trading

Extended periods of lower prices for oil, NGLs and natural gas can have a material adverse impact on our results of operations, financial condition and liquidity. Among other things, our earnings, cash flows and capital expenditure programs could be negatively affected, as could our production and our estimates of proved reserves. A significant or sustained decline in liquidity could adversely affect our credit ratings, potentially increase financing costs and reduce access to capital markets. We may be unable to realize anticipated cost savings and expenditure reductions that are intended to compensate for such downturns. In addition, extended periods or low commodity prices can have a material adverse impact on the results of operations, financial condition and liquidity of our suppliers, vendors, partners and customers upon which our own results of operations and financial condition depends.depend.

In order to manage our exposure to price risk in the marketing of our production, we have entered into commodity derivative positions with respect to a portion of our expected future production from oil and natural gas, and may in the future enter into commodity derivative positions with respect to oil or natural gas. See Financial Statements and Supplementary Data– Note 1110 –Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on our derivative contracts and transactions. While these commodity derivative positions are intended to reduce the effects of price volatility, they may also limit future income if prices were to rise substantially over the price established by such positions. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which there is a widening of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements or the counterparties to the derivative contracts fail to perform under the terms of the contracts.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel. Many of our competitors have financial resources that allow them to obtain substantially greater technical expertise and personnel than we have. We actively compete with other companies in our industry when acquiring new leases or oil and natural gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to pay more to acquire productive oil and natural gas properties and exploratory prospects than we are able or willing to pay or finance. Finally, companies with larger financial resources may have a significant advantage in terms of meeting any potential new bonding or financial assurance requirements. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

A portion of our oil and natural gas is processed for sale on platforms owned by third parties with no economic interest in our wells and no other processing facilities would be available to process such oil and natural gas without significant investment by us. In addition, third-party platforms could be damaged or destroyed by tropical storms, hurricanes or other weather events, which could reduce or eliminate our ability to market our production. As of December 31, 2024,2025, fourtwo fields, accounting for approximately 3.71.0 MMBoe (or 2.9%0.8%) of our total proved reserves, are tied back to separate, third-party owned platforms. Although we have entered into contracts for the process of our production with the owners of such platforms, there can be no assurance that the owners of such platforms will continue to process our oil and natural gas production.

Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and further lower the level of activity and depresseddepress values in the oil and natural gas property sales market.

We annually re-evaluate the purchase of insurance, policy limits and terms annually.terms. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. The occurrence of a significant event for which our losses are not fully insured or indemnified, or for which the insurance companies will not pay our claims, could have a material adverse effect on our financial condition and results of operations.

In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. CurrentlyCurrently, the OPA requires owners and operators of offshore oil production facilities to have ready access to between $35.0 million and $150.0 million, which amount is based on a worst case oil spill discharge volume demonstration that can be used to cover costs that could be incurred in responding to an oil spill at our facilities on the OCS. We are currently required to demonstrate that we have ready access to $70.0 million. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement.

As of December 31, 2024,2025, we operate 86.1%86.7% of our wells. AsFor those wells that we carry out our drilling program, we maydo not serve as operator of all planned wells. In that case,operate, we have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities.

Oil and natural gas exploration and production activities involve certain risks that a combination of experience, knowledge and careful evaluation may not be able to overcome. Our future success will depend on the success of our exploration and production activities and on the future existence of the infrastructure and technology that will allow us to take advantage of our findings. Additionally, some of our properties are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with exploration and production activities. As a result, our exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

For 2024,2025, approximately 35%36% of our production and 15%20% of our total revenue was attributable to our interests in certain oil and natural gas leasehold interests and associated wells and units located off the coast of Alabama, in state coastal and federal Gulf of America waters approximately 70 miles south of Mobile, Alabama (the “Mobile Bay Properties”). This concentration means that any impact on our production from this field, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment or otherwise, could have a material adverse effect on our business. During 2024,2025, our Mobile Bay Properties were shut-in for various reasons, including Hurricane Helene, compressor problems and downstream operated plant issues. These shut-ins resulted in deferred production of approximately 850686 MBoe based on production rates prior to the shut-ins. Any additional shut-ins, depending on the duration of the shut-in, could have a material adverse impact on our business. In addition, if the actual reserves associated with the Mobile Bay Properties are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies.technologies (such as the use of artificial intelligence and machine learning). As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologiestechnologies, provide enhancements and new integrations from our existing platforms, develop new products that achieve market acceptance or innovate quickly enough to keep pace with rapid technological developments at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before we can. We rely heavily on the use of advanced seismic technology to identify exploitation opportunities and to reduce our geological risk. Seismic technology or other technologies that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

You should not assume that the standardized measure of discounted future net cash flows or the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

We expect to grow by expanding the exploitation and development of our existing assets, in addition to making targeted acquisitions in the Gulf of America. We may not realize all of the anticipated benefits from future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices. This could lead to potential adverse short-term or long-term effects on our financial and operating results.

We rely on our information technology (“IT”) infrastructure and management information systems to operate and record aspects of our business. Although we take security measures to protect against cybersecurity risks, including unauthorized access to our confidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach. Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks.attacks as of the date of this Form 10-K. Security breaches include, among other things, illegal hacking, computer viruses, interference with treasury function, theft or acts of vandalism or terrorism. A breach could result in an interruption in our operations, malfunction of our platform control devices, disabling of our communication links, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data, violation of privacy or other laws and exposure to litigation. Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows. TheGeopolitical invasiontensions, of Ukraine by Russia,sanctions, and the impact of world sanctions against Russia and the potential for retaliatory acts from Russia,actions could result in increased cybersecurity attacks against U.S. companies.

Such circumstances or conflicts might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership and lender relationships may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations or with such potential conflicts.

In January 2025, we issued $350.0 million in aggregate principal amount of our 10.75% Senior Second Lien Notes due 2029 (the “10.75% Notes”) and entered into a new credit agreement with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million (the “New Credit Agreement”). The indenture (the “2025 Indenture”) governing our 10.75% Notes and our New Credit Agreement contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt. These covenants limit our ability and the ability of certain subsidiaries, among other things, to:

Our New Credit Agreement requires us, among other things, to maintain certain financial ratios and satisfy certain financial condition tests. These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from the restrictive covenants under our 2025 Indenture and our New Credit Agreement.

Our New Credit Agreement and our 10.75% Notes are secured by various liens on our oil and natural gas properties. Any future borrowings under our New Credit Agreement would be secured on a first priority basis by the assets securing the 10.75% Notes. If the proceeds of the sale of the collateral securing the 10.75% Notes or any future indebtedness incurred under the New Credit Agreement are not sufficient to repay all amounts due in respect of such debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured, and our ability to pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.

If we experience certain kinds of changes of control, we must give holders of the 10.75% Notes the opportunity to sell us their notes at 101% of their principal amount, plus accrued and unpaid interest. However, in such an event, we might not be able to pay the holders the required repurchase price for the notes they present to us because we might not have sufficient funds available at that time, or the terms of our New Credit Agreement or other agreements we may enter into in the future may prevent us from applying funds to repurchase the 10.75% Notes. The source of funds for any repurchase required as a result of a change of control will be our available cash or cash generated from our oil and gas operations or other sources, including:

On August 14, 2024, we filed a complaint seeking declaratory relief (the “Original Complaint”) in the U.S. District Court for the Southern District of Texas, Houston Division, against Endurance Assurance Corporation and Lexon Insurance Company (the “Sompo Sureties”), providers of private and government-required surety bonds that secure decommissioning obligations we may have with respect to certain of our oil and natural gas assets (the “Sompo Sureties Litigation”). As described in the Original Complaint, we have paid all negotiated premiums associated with the bonds issued by the Sompo Sureties prior to the Original Complaint and have not suffered a material change to our financial status. Despite this, the Sompo Sureties issued us written demands requesting we provide collateral to the Sompo Sureties. On October 9, 2024, the Sompo Sureties filed an answer and counterclaim alleging breach of contract due to our failure to provide the collateral demanded by the Sompo Sureties. The Sompo Sureties originally issued approximately $55.0 million in surety bonds on our behalf. However, the BOEM cancelled a $13.1 million bond after we fulfilled our decommissioning obligations. Despite this, the Sompo Sureties have requested approximately $55.0 million in cash collateral.

To the extent that the Sureties succeed in forcing us to fulfill the Demanded Collateral, or in the event that other surety entities attempt to do the same, the fulfilment of such demands could be significant and our liquidity position will be negatively impacted, and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be: forced to reduce our capital expenditures in the current year or future years; unable to execute our ARO plan; or unable to comply with our existing debt instruments.

IfA we failfailure to comply with theBOEM’s newfinancial ruleassurance andrequirements suchcould future orders, thecause BOEM couldto commence enforcement proceedings or take other remedial action against us, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition. In addition, if we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted, and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures.

The Biden administration took a number of actions that had potential to result in stricter environmental, health and safety standards applicable to our operations and those of the oil and natural gas industry more generally. Issuance of new or amended rulemakings restricting deepwater leasing, permitting or drilling could result in more stringent or costly restrictions, delays or cancellations to our operations as well as those of similarly situated offshore energy companies on the OCS. Compliance with any added or more stringent regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives, could adversely affect or delay new drilling and ongoing development efforts.

We are subject to numerous lawslaws, rules, regulations and regulationspolicies that can adversely affect the cost, manner or feasibility of doing business.

CalculationThe IRA contains hundreds of thebillions feeof is based on certain thresholds establisheddollars in theincentives IRA. In addition,for the multipledevelopment of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.

PresidentThe Biden made addressing the threat of climate change from GHG emissions a priority under his administration, and regulatory agencies under the Biden administration issued rules in supportreturn of President Biden’sTrump regulatoryto andthe politicalWhite agenda,House whichin includedJanuary reducing2025 dependencetriggered on,a andsweeping use of, fossil fuels and curtailmentrollback of hydraulicUnited fracturingStates onclimate federalpolicy, lands.reversing Sincemany takingof officethe ininitiatives introduced under former President Biden. In January 2025, President Trump hasannounced takenthat actionsthe toUnited reverseStates manywas ofwithdrawing thesefrom Biden-erathe rulesUnited andNations-sponsored policies.“Paris PresidentAgreement.” TrumpHe in January 2025also issued additional executive orders aimed at boosting fossil fuels and undoing Biden-era initiatives to limit GHG emissions. He declared a national energy emergency and revoked many of Biden’s executive orders on climate change. New orders instruct agencies to roll back restrictions on offshore drilling and reconsider protections for Alaska’s Arctic National Wildlife Refuge. President Trump also issued a moratorium on new wind power projects on federal lands, pausing new leases and permits for both onshore and offshore wind farms. He revoked an executive order that compelled government regulators to assess the risks of climate change to the financial system and he instructed agencies to review any regulations that might “burden the development of domestic energy resources.” ThatThese couldexecutive includeorders majorand Bidenthe administrationsubsequent changes to regulations have had a tangible impact on the regulatory environment as it relates to climate policies,change. includingAdditionally, EPAon rulesFebruary limiting12, 2026, EPS Administrator Lee Zeldin signed a final rule repealing the EPS’s 2009 finding that emissions fromof coal-carbon dioxide, methane and naturalother gas-firedGHGs powerpresent plantsan endangerment to public health and newthe feesenvironment. onWe methaneanticipate emissions fromthat the oilfinal andrule, gasone industry.published in the Federal Register, will be the subject of widespread litigation.

Additionally, increasing attention from consumers and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial preferences and behavior and societal pressure on companies to address climate change may result in increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, geothermal, tidal and biofuels as well as electric vehicles) and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products.

Increasing attentionAttention to ESG matters may impact our business.

Increasing scrutiny related to ESG matters, societal expectations for companies to address climate change and sustainability concerns, and investor, societal, and other stakeholder expectations regarding ESG and sustainability practices and related disclosures may result in increased costs, reduced demand for the oil and natural gas we produce, reduced profits, increased risks of governmental investigations and private party litigation, and negative impacts on our stock price and access to capital markets. Increasing attentionAttention to climate change, for example, may result in demand shifts for the hydrocarbon products we produce as well as additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the assented damage, or to other mitigating factors.

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with Part I, Item 1. Business, Item 1A. Risk Factors, Item 2. Properties and Item 7A. Quantitative and Qualitative Disclosures About Market Risk and with Part 1I,II, Item 8. Financial Statements and Supplementary Data and other financial information appearing elsewhere in this 20242025 Form 10-K. The following discussion and analysis includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Part I, Item 1A. Risk Factors.

RecentSignificant Developments

Termination of Legacy Credit Agreement and Entry into New Credit Agreement

On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we terminated our Sixth Amended and Restated Credit Agreement (the “Legacy Credit Agreement”) and entered into the New Credit Agreement which provides us a revolving credit and letter of credit facility with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million. The New Credit Agreement matures on July 28, 2028.

The EIA published its latest Short-Term Energy Outlook in January 2025.2026. The EIA expects downward oil priceprices pressuresto overdecline muchin of the next two years2026, as they expect that global oil production will grow more thanexceeds global oil demand.demand, causing inventories to rise. The EIA forecasts that the spot price for WTI oil will average $70.33$52.25 per barrel in 2025,2026, 8%20% less than 2024,the andaverage thenprice continueof to fall another 11% to $62.50$65.46 per barrel in 2026.2025 and then average $50.33 per barrel in 2027. The unwinding of OPEC+ production cuts and strong growth in oil production outside of OPEC+ results in global oil production growing in the EIA forecast. Although the EIA is forecasting OPEC+ will increase production, they expect the group will produce less oil than stated in its most recent production target in an effort to avoid significant inventory builds.

The EIA expects the spot prices for Henry Hub natural gas to average $3.14 per MMBtu in 2025 and $3.97$3.46 per MMBtu in 2026, updown 2% from athe historically low2025 average of $2.19$3.53 per MMBtu, and average $4.59 per MMBtu in 2024.2027. The EIA expects wholesale natural gas prices to increase becausedue to growth in demand, led by expanding liquified natural gas exports, will outpace production growth and keepmore inventoriesnatural gas consumption in the nextelectric twopower yearssector atfrom orgrowing belowdemand theirfor previouspower five-yearin averages.the commercial and industrial sectors.

In addition, ourOur oil, NGLs and natural gas production can also be significantly affected by both planned and unplanned production downtime caused by events such as planned repairs and upgrades, third-party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events. For 2024,2025, we estimate deferred production was approximately 2.62.5 MMBoe, excluding the deferred production from the hurricanes.MMBoe.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. In April 2024, BOEM released a final rule that changes the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements. Under the new rule, BOEM streamlined the criteria used to evaluate the financial health of an energy company down to two factors: (i) the company’s credit rating, and (ii) the ratio of the value of the company’s proved reserves to decommissioning liability associated with those reserves. The new rule also codifies the usage of BSEE decommissioning estimates to evaluate supplemental financial assurance requirements and allows third party guarantors (upon agreement with BOEM) to provide limited guarantees to specific amounts or specific leases instead of the blanket guarantees that have been used in the past. Finally, the new rule also requires a base financial assurance requirement of $500,000 for federal RUEs to match the requirement for state RUEs. To provide the industry with flexibility to meet the new financial assurance requirements, BOEM will allow current lessees and grant holders to request phased-in payments over a three-year period. BOEM estimates that the industry will be required to provide $6.9 billion in new financial assurances under the new rule, which took effect on June 29, 2024. Following the announcement of the new rule, a series of lawsuits from both states and industry groups have been filed against BOEM to block the implementation of the new rule. We are actively monitoring ongoing litigation with respect to the new rule. However, President Trump may seek to suspend, revise or rescind this final rule pursuant to Interior Secretary Burgum’s Secretarial Order 3418 dated February 2, 2025. The substance and timing of such legal and regulatory actions cannot be predicted at this time. The future cost of compliance with respect to supplemental financial assurances, including the obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of BOEM’s final rule or any new, more stringent, rules related to supplemental financial assurances could materially and adversely affect our financial condition, cash flows, liquidity and results of operations. Additionally, regardless of the final rule, BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. For more information on the BOEM and financial assurance obligations to that agency, see Business – Environmental, Health and Safety Matters and Government Regulations – Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 of this Form 10-K.

In prior years, some of the sureties, which provided us surety bonds that we use for supplemental financial assurance purposes, requested and received collateral from us. Pursuant to the terms of our agreement with various sureties under outour existing bonding arrangements, we may be required to post collateral. These sureties may request additional collateral from us in the future, which could be significant and could materially impact our liquidity.

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, NGL and natural gas revenues do not include the effects of derivatives, which are reported in Derivative (gain) loss,gain, net in our Consolidated Statements of Operations.

Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, insurance premiums, workover costs and facility maintenance expenses. Our lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $23.8$17.3 million to $298.8 million in 2025 compared to $281.5 million in 2024 compared to $257.7 million in 2023.2024. On a per Boe basis, lease operating expenses increased to $24.09 per Boe during 2025 compared to $23.10 per Boe during 2024 compared to $20.24 per Boe during 2023.2024. On a component basis, base lease operating expenses increased $30.2$10.0 million, workover expenses increased $5.6 million and facility maintenance expenses increased $7.9$2.7 million and hurricane repairs increased $1.0 million,million. These increases were partially offset by a decrease of $15.3$1.0 million in workoverhurricane expenses.repairs.

Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base lease operating expense. Base lease operating expenses increased primarily due to increases of $37.5 million of expenses at the fields acquiredbrought online during 2025 and increased repairs and maintenance in Januaryvarious 2024 and September 2023fields, partially offset by $6.1a millionfull year of a cost sharing agreement that began in mid-2024, cost reductions in several fields and reduced expenses from the abandonment work to shutdown certain of our fields.

Workover and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. The decreaseincreases in workover expenses and the increase in facilities maintenance expenses were due to the timing and mix of projects undertaken.

Hurricane expenses consist of costs for minor repairs and restoring production, as well as evacuating employees and contractors incurred as a result of Hurricanes Francine, Helene and Rafael.Rafael during 2024.

Gathering and transportation consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale. Production taxes consist of severance taxes levied by the Alabama Department of Revenue ,Revenue, the Louisiana Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state. Gathering, transportation and production taxes increaseddecreased to $25.7 million in 2025 compared to $28.2 million in 2024 compared to $26.3 million in 2023,2024, primarily due to increase of $1.5 million in gathering and transportation fees and $0.4 million in production taxes. Gathering and transportation fees increased during the first half of 2024 compared with the first half of 2023 primarily related to higher production volumes in the first quarter of 2024 and higher processing fees for our Mobile Bay production that had to be re-routed to a different processing plant due to the shut-in of our primary Mobile Bay processing plant.plant Theseduring fees decreased in the second half of 2024 as our production volumes decreased compared with the same period in 2023. The increase in production taxes is primarily related to the start of payments to the state of Louisiana from our acquisition of oil and natural gas properties in September 2023.2024.

Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. DD&A increaseddecreased $28.3$26.6 million for 20242025 compared to 20232024 primarily due to increases of $33.3$28.6 million from ana increasedecrease in the depletion rate per Mcfe and $1.3 million for depreciation of other property and the corporate airplane acquired in May 2023, partially offset by $6.3$2.0 million from the decreaseincrease in production for 20242025 compared with 2023.2024. The DD&A rate increaseddecreased to $9.39 per Boe in 2025 from $11.74 per Boe in 2024 from $9.01 per Boe in 2023.2024. The DD&A rate per Boe increaseddecreased primarily as a result of a higher depreciable base due to our January 2024 acquisition, increasesdecreases in capital expenditures, future development costs and capitalized ARO anda lower depreciable base, partially offset by decreased proved reserves. The lower depreciable base is due to the $58.5 million in insurance proceeds and $11.9 million of proceeds from the sale of oil and natural gas properties that were included in our full cost pool.

Accretion expense is the expensing of the changes in value of our ARO as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. Accretion expense increased to $33.4 million in 2025 compared to $32.4 million in 2024 compared to $29.0 million in 2023 primarily due to ourthe acquisitionincrease in Januaryour 2024ARO andliability as a result of revisions to the estimates used in calculating the liability.

General and administrative (“G&A”) expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance. For 2024,2025, G&A expenses were $82.4$80.0 million compared to $75.5$82.4 million in 2023.2024. The increasedecrease is primarily due to increasesa decrease of (i) $4.0 million in payroll costs consisting of $1.8 million related to merit and headcount increases and a $2.2 million employee retention credit recorded in 2023, (ii) $2.8$4.6 million in non-recurring legal fees and (iii)professional $1.9 million in medical claims cost,fees, partially offset by a $2.1$2.0 million decreaseincrease in short-term incentiveshare-based compensation costs.

Interest expense, net of interest income, decreased $4.2$4.0 million for 20242025 compared with 20232024 primarily due to decreasesa decrease of $7.9$42.3 million from the redemption in February 2023 of ourthe 9.75% Senior Second Lien11.75% Notes due 2023 and $1.9 million from the lower outstanding principal balancerepayment of the Term Loan,Loan in late January 2025, partially offset by $2.8$37.3 million incurred on the 11.75%10.75% Notes issued in late January 2023 and a $2.6 million decrease in interest income.2025.

Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month. During 2025, the $13.6 million derivative gain consisted of $16.3 million of realized gains on settled contracts offset by a $2.7 million unrealized loss from the decrease in the fair value of the open contracts. During 2024, the $3.6 million derivative gain consisted of $2.9 million of realized gains on settled contracts and $0.7 million of unrealized gain, net, from the increase in the fair value of the open contracts. During 2023, the $54.8 million derivative gain consisted of $4.1 million of realized losses on settled contracts and $58.9 million of unrealized gain, net, from the increase in the fair value of the open contracts.

Our effective tax ratesrate for 20242025 was not meaningful and 2023 were 10.3% and 54.0%, respectively. These rates differed from the federal statutory rate primarily due to the recording of 21%a $71.2 million valuation allowance in 2025 against our net deferred tax assets as it is more likely than not that our deferred tax assets in excess of our deferred tax liabilities will currently not be utilized. Our effective tax rate for 2024 was 10.3% and differed from the federal statutory rate primarily due to the impact of state income taxes, non-deductible compensation and adjustments to the valuation allowance on our deferred tax assets.

We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of December 31, 2024,2025, we had $109.0$140.6 million of available cash on hand and $50.0$43.9 million available under our Credit Agreement, based on a borrowing base of $50.0 million.million and $6.1 million of letters of credit outstanding. We also have up to approximately $83.0 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment and will allow us to meet our cash requirements for at least the next 12 months and beyond.

The following table summarizes cash flows provided by (used in) byeach type of activity for the following periods (in thousands):

Operating activities – Net cash provided by operating activities for 20242025 was $59.5$77.2 million, decreasingincreasing $55.8$17.7 million from 2023.2024. This was primarily due to decreasesan increase of $37.6 million in net (loss) income adjusted for certain non-cash items and $18.2$29.6 million from changes in operating assets and liabilities.liabilities Theoffset by a decrease of $11.9 million in net (loss) income adjusted for certain non-cash items was primarily related to a $7.4 million decrease in revenues and increases in cash operating expenses, partially offset by a $13.5 million increase in derivative cash receipts.items. The decreaseincrease in operating assets and liabilities is primarily related to lower accounts receivable balances due to decreased revenues partially offset by higher accounts payable and accrued liabilities balances in the current period. The decrease in net loss adjusted for certain non-cash items was primarily related to a $23.8 million decrease in revenues and increases in cash operating expenses, partially offset by a $10.1 million increase in derivative cash receipts.

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of America. As of MarchJune 31,30, 2026, we hold working interests in 48 producing offshore fields in federal and state waters (which include 41 fields in federal waters and seven in state waters). We currently have under lease approximately 605,200591,000 gross acres (471,300457,100 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,600 gross acres in Alabama state waters, 457,700449,200 gross acres on the conventional shelf and approximately 141,900136,200 gross acres in the deepwater. A majority of our daily production is derived from wells we operate.

On MayAugust 7,5, 2026, we declared a regular quarterly dividend of $0.01 per share of common stock for the secondthird quarter of 2026. We expect to pay the dividend on MayAugust 28,26, 2026 to stockholders of record as of the close of business on MayAugust 21,19, 2026.

The Henry Hub spot price averaged $4.80$2.95 per MMBtu for the firstsecond quarter of 2026, and the EIA expects the spot prices for Henry Hub natural gas to average $3.29$3.47 per MMBtu for the remainder of 2026 and average $3.59$3.49 per MMBtu in 2027. The EIA expects wholesalethat record natural gas pricesproduction towill remainhelp closemeet torising recentdemand seasonalfrom normsthe aselectric power sector, putting moderate downward pressure on natural gas storage levels remain at average levels.prices.

Three Months Ended MarchJune 31,30, 2026 Compared to the Three Months Ended MarchJune 31,30, 2025

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, NGL and natural gas revenues do not include the effects of derivatives, which are reported in Derivative gain,loss (gain), net in our Condensed Consolidated Statements of Operations.

Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended MarchJune 31,30, 2026 and 2025 (in thousands):

Production volumes increased by 515105 MBoe to 3,2593,157 MBoe during the three months ended MarchJune 31,30, 2026 compared to the same period in 2025 primarily due to restoring production at our West Delta 73, MO 91673 and MainEugene PassIsland 10864 fields and increasedrecompletion of a well at our Garden Banks 783 field, partially offset by reduced production fromat our Mobile Bay fields due to reduceda downtime,temporary partiallyre-route offsetof byproduction shut-insdue atto ourthird-party SS 349 field for approximately five days.maintenance.

Lease operating expenses – Lease operating expenses (“LOE”) include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, insurance premiums, workover costs and facility maintenance expenses. LOE, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, decreased $4.9$5.4 million during the three months ended MarchJune 31,30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $20.29$22.67 per Boe during the three months ended MarchJune 31,30, 2026 compared to $25.88$25.20 per Boe during the three months ended MarchJune 31,30, 2025. On a component basis, base LOE decreased $5.2$2.5 million, workover expenses decreased $0.7$1.1 million, facilities maintenance expense increaseddecreased $1.1$1.9 million and hurricane repairs decreasedincreased $0.1 million.

Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base LOE. These costs decreased primarily due to lower costs overall, reflecting the success of our cost reduction efforts that began in the fourth quarter of 2025 and continued into the three months ended MarchJune 31,30, 2026.

Workover and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. The increasesdecreases in workover expenses and facilities maintenance expenses were due to the timing and mix of projects undertaken.

Gathering, transportation and production taxes – Gathering and transportation consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale. Production taxes consist of severance taxes levied by the Alabama Department of Revenue, the Louisiana Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state. Gathering, transportation and production taxes increased $3.0$1.1 million for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the three months ended MarchJune 31,30, 2026.

Depreciation, depletion and amortization – Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. DD&A decreased $5.6$0.9 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended MarchJune 31,30, 2025 primarily due to a decrease of $11.6$1.6 million from the decrease in the depletion rate per thousand cubic feet equivalent (“Mcfe”) offset by an increase of $6.0$0.9 million from the increase in production. The DD&A rate decreased to $8.37$8.10 per Boe for the three months ended MarchJune 31,30, 2026 from $11.99$8.67 per Boe for the three months ended MarchJune 31,30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, partially offset by decreased proved reserves.

General and administrative expenses – General and administrative (“G&A”) expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance. G&A expenses increased $4.7$9.8 million for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025 primarily due to an increaseincreases of $5.4$8.2 million in share-based compensation costs,costs partiallyand offset by a $1.0$1.1 million decrease in employeelegal payrolland costs.professional fees.

Income tax expense (benefit) – Our effective tax rates for the three months ended MarchJune 31,30, 2026 and 2025 were (13.312.2)% and 13.1%,10.2%, respectively, and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit and adjustments to the valuation allowance.

We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of MarchJune 31,30, 2026, we had $130.9$150.7 million of unrestricted cash on hand and $43.9$43.4 million available under our Credit Agreement, based on a borrowing base of $50.0 million and $6.1$6.6 million of letters of credit outstanding. We also have up to approximately $83.0 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth and will allow us to meet our cash requirements for at least the next 12 months and beyond.

Net cash provided by operating activities increased $5.7$11.1 million in the threesix months ended MarchJune 31,30, 2026 compared to the corresponding period in 2025. This was primarily due to an increase of $25.5$53.2 million in net loss adjusted for certain noncash items and a decrease of $19.7$42.1 million in operating cash flows from changes in operating assets and liabilities. The increase in net loss adjusted for certain noncash items was primarily related to increases of $20.2$60.4 million in revenues andoffset $5.6by an increase of $16.4 million in derivative settlements. The decrease in operating assets and liabilities is primarily related to higher ARO settlements and unfavorable changes in accounts receivable, offset by favorable changes in accounts payable,payable and accrued liabilities and other.

Our principal recurring investing activity is the funding of acquisitions and investments in oil and natural gas properties to support and generate revenues from operations. Cash flows (used in) provided by investing activities were $(10.319.0) million and $63.3$52.5 million during the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. Investments in oil and natural gas properties were $10.1$18.8 million and $6.7$17.1 million during the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. During the threesix months ended MarchJune 31,30, 2025, we received $58.5 million in insurance proceeds and $11.9 million in proceeds from the sale of oil and natural gas properties. As we use the full cost method of accounting for our oil and natural gas properties, these proceeds were recorded in our full cost pool.

Cash flows used in financing activities were $1.9$6.8 million and $63.1$65.6 million for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. In connection with our debt refinancing in January 2025, we received $350.0 million in proceeds from the issuance of our 10.75% Notes and used these proceeds, along with cash on hand, to (i) purchase for cash, pursuant to a tender offer, $269.8 million of our 11.75% Senior Second Lien Notes due 2026 (the “11.75% Notes”); (ii) repay $114.2 million of amount outstanding under the credit agreement of certain of our indirect, wholly-owned subsidiaries; (iii) purchase $5.9 million of government securities to be used in the legal defeasance of the remaining principal of our 11.75% Notes not validly tendered and accepted for purchase in the tender offer; and (iv) pay $21.3 million in premiums, fees and debt issuance costs.

As of March 31, 2026, we expect to incur an additional $12.0 million to $18.0 million of capital expenditures in the remainder of 2026, which excludes acquisitions. In our view of the outlook for the remainder of 2026, we believe thisour expected level of capital expenditure will leave us with sufficient liquidity to operate our business, while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.

We have obligations to plug and abandon wells, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. Through the threesix months ended MarchJune 31,30, 2026, we have paid $17.2$20.6 million related to these obligations. Our ARO estimates as of MarchJune 31,30, 2026 and December 31, 2025 were $566.0$573.2 million and $561.9 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Part I, Item 1A. Risk Factors, of our 2025 Annual Report for additional information.

As of MarchJune 31,30, 2026, we have $358.6$358.3 million in aggregate principal amount of long-term debt outstanding, with $8.6$8.3 million in aggregate principal coming due over the next twelve months.

During the threesix months ended MarchJune 31,30, 2026, we declared a cash dividenddividends of $0.01$3.2 permillion shareto holders of our common stock. The dividend was paid on March 26, 2026 to stockholders of record as of the close of business on March 19, 2026. The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors.