W&T OFFSHORE INC
For the period ended Dec 31, 2025. Filed Mar 16, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Mar 16, 2026
WTI$3.09-1.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-03-04.
0001558370-25-002116
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-16.
0001104659-26-028315
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 130 previous paragraphs and 132 current paragraphs.
71 unchanged; 36 reworded; 24 added; 21 removed; 2 previous and 1 current paragraphs rearranged.
Tables are not compared: 11 previous and 11 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (24)
Current report
Significant Developments
Current report
Receipt of Insurance Proceeds
Current report
Appeal with the Office of Natural Resources Revenue
Current report
On August 26, 2025, the United States District Court for the Eastern District of Louisiana issued a favorable order on the Company’s motion for summary judgment regarding the disallowance of allowable reduction of cash payments for royalties owed to the ONRR. On December 15, 2025 and December 16, 2025, the ONRR released the Company’s administrative appeal bonds. The Company remains in discussions with the ONRR regarding the related litigation bond and the amount, if any, to be refunded or credited to the Company. As a result of the order, the Company reversed its $5.3 million accrual related to this matter.
Current report
Bonding Disputes
Current report
On June 14, 2025, we entered into the USSIC Settlement Agreement and, on June 15, 2025, we entered into the PIIC Settlement Agreement to dismiss all claims with the applicable parties related to the Sureties Litigation without prejudice. Pursuant to the applicable Settlement Agreement, USSIC and PIIC agree that: (i) there will be no change to the 2024 premium rates paid by us or any of its affiliates, subsidiaries or joint venture entities, for any currently existing surety bond executed by USSIC or PIIC until after December 31, 2026, at the earliest, (ii) USSIC and PIIC withdraw all demands for collateral and agree not to request, demand, or otherwise insist on collateral, whether related to a surety bond or pursuant to the indemnity agreements, until after December 31, 2026, at the earliest; provided that such restriction shall not apply if (a) we do not pay premiums owed to USSIC or PIIC when due; (b) a claim is made by a third party against any bond issued by USSIC or PIIC to us or its affiliates or subsidiaries; (c) there is an initiation of an insolvency proceeding for us or any of its affiliates, subsidiaries or joint venture entities, whether voluntary or involuntary; (d) there is an uncured event of default under the indenture governing our second lien notes due 2029 that results in an acceleration, in whole or in part, of the indebtedness thereunder; or (e) we or our affiliates or subsidiaries initiate a lawsuit against USSIC or PIIC. Each of the Settlement Agreements also provides that, in the event that we enter into an agreement to provide collateral to another party in settlement of the Sureties Litigation on bonds existing as of the date of the Settlement Agreement, we shall, on a pro rata basis, provide substantially similar collateral to USSIC or PIIC as it does to such other party. The entry into the Settlement Agreements resulted in the withdrawal of approximately $94 million in collateral demands.
Current report
On June 30, 2025, we announced that the presiding judge in the Sureties Litigation recommended denying the requests for preliminary injunction submitted by two surety providers. The preliminary injunction would have required us to immediately post $105 million of collateral. The recommendation would effectively nullify all current collateral requests related to the surety litigation by the surety providers and we will not be required to post collateral (if at all) until a determination on the merits of the Sureties Litigation with the remaining surety providers.
Current report
All of the remaining parties to the Sureties Litigation previously agreed to mediate the case until the mediator declares an impasse. Mediation is no longer active as the mediator has declared an impasse with respect to the surety providers that did not enter into the Settlement Agreements. We continue to evaluate potential avenues for resolution of the remaining related premium and collateral-related matters.
Current report
First Quarter 2026 Dividend
Current report
On March 5, 2026, we declared a first quarter dividend of $0.01 per share. We expect to pay the dividend on March 26, 2026 to stockholders of record on March 19, 2026.
Current report
We are also monitoring the impact of the tariffs announced by the United States federal government in 2025 and 2026. While there is significant uncertainty as to the duration of these and any further tariffs, and the impacts these tariffs and any corresponding retaliatory tariffs will have on the oil and gas industry and on commodity prices, we do not currently expect that the financial impact of the tariffs will be material to capital expenditures or operating expenses in 2026.
Current report
The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS. In April 2024, BOEM released a final rule that changed the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements. Under the new rule, BOEM revised the criteria for determining whether OCS oil and natural gas lessees and grant holders are required to provide supplemental financial assurance to backstop their decommissioning obligations. On April 8, 2025, pursuant to directives from the Trump administration, the DOI, through a joint filing in the U.S. District Court for the Western District of Louisiana (Case no. 2:24-cv-00820), indicated that it will not seek supplemental financial assurance in the Gulf of America except in the case of (a) sole liability properties and (b) certain non-sole liability properties that do not have a financially strong
Current report
co-owner or predecessor in title and meet other conditions. Further, in May 2025, the DOI announced its intent to revise the rule, and in March 2026, BOEM published a proposed rule setting forth amendments to the existing financial assurance regulatory framework. The proposed rule would, among other things, (i) permit BOEM to consider the financial strength of predecessors with joint and several liability when determining whether supplemental financial assurance is required, (ii) revise the level of BSEE probabilistic estimates of decommissioning cost used for determining the amount of supplemental financial assurance required from P70 to P50, (iii) provide BOEM with discretion, in circumstances where decommissioning is scheduled to occur within one year of a supplemental financial assurance demand, to accept third-party decommissioning contracts or decommissioning schedules in lieu of requiring new supplemental financial assurance, (iv) eliminate the requirement that a lessee challenging a supplemental financial assurance demand post an appeal bond equal to the amount of the demand in order to obtain a stay pending appeal, and (v) explicitly recognize dual-obligee bonds (which identify multiple obligees) as an acceptable form of financial assurance. The proposed rule is subject to a 60-day public comment period, which is expected to end on May 8, 2026.
Current report
Production volumes increased by 219 MBoe to 12,402 MBoe during 2025 compared to the same period in 2024, primarily due to restoring production at our West Delta 73, MO 916 and Main Pass 108 fields and increased production at our Mobile Bay fields due to well stimulation work and reduced downtime, partially offset by unplanned third party pipeline outages and the shut-in of a well due to solids production.
Current report
Loss on extinguishment of debt** **
Current report
During 2025, we recorded a loss on extinguishment of debt related to our January 2025 refinancing. The loss consisted of (i) $9.8 million of premiums paid on the redemption of the tendered 11.75% Notes; (ii) $4.6 million related to the write-off of unamortized debt issuance costs; (iii) $0.5 million of fees related to the refinancing; and (iv) $0.2 million related to the legal defeasance of the untendered 11.75% Notes.
Current report
During 2025, other expense, net, was $8.4 million, compared to $18.1 million for 2024. The decrease in other expense, net was primarily due to (i) the release of an accrual of $5.3 million related to our dispute with the ONRR, (ii) a $3.4 million decreasein the accrual of additional expenses for net abandonment obligations related to our assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or have been unable to perform required abandonment obligations and (iii) an increase of $1.9 million in income from unconsolidated affiliates in 2025.
Current report
Income tax expense (benefit)
Current report
Operating activities
Current report
Our largest source of operating cash is collecting cash from customers and joint interest partners from sales of our products. The primary use of operating cash is to pay our suppliers, employees and others for a wide range of goods and services.
Current report
Investing activities
Current report
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. Net cash provided by investing activities for 2025 increased $140.0 million compared to 2024. During 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. This increase in cash flows and a $79.9 million decrease in acquisition of property interests was partially offset by an $11.3 million increase in investments in oil and natural gas properties.
Current report
Financing activities
Current report
Net cash used in financing activities during 2025 increased by $60.5 million compared to 2024. 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 the Tender Offer, $269.8 million of our 11.75% Notes; (ii) repay $114.2 million of amount outstanding under our Term Loan; (iii) purchase $5.3 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 $21.8 million in premiums, fees and debt issuance costs.
Removed paragraphs (21)
Previous report
Recent Developments
Previous report
Business and Operational Updates
Previous report
On January 16, 2024, we closed on our acquisition of rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of America, among other assets, for $77.3 million (including closing fees and other transaction costs). The acquisition was funded using cash on hand. We also assumed the related
Previous report
AROs associated with these assets. This transaction is described in more detail underFinancial Statements and Supplementary Data –Note 2 – Acquisitions, under Part II, Item 8 of this Annual Report.
Previous report
In December 2024, we entered into a purchase and sale agreement to sell a non-core interest in the Garden Banks Blocks 385 and 386. The effective date of the sale was December 1, 2024, and the transaction closed on January 8, 2025 for approximately $11.9 million following customary purchase price adjustments.
Previous report
Effective December 20, 2024, we entered into a resolution with the third-party pipeline operator at our West Delta 73 field. As a result of this resolution, we expect to restart production from the field in the second quarter of 2025. We originally acquired the West Delta 73 field in our January 2024 acquisition.
Previous report
In June 2024, we received notice from BSEE that we would be required to cease production at our Main Pass 108 and 98 fields as the result of a shut-in of midstream infrastructure not owned by us. On December 11, 2024, we entered into a purchase agreement and other arrangements with the trustee of the bankruptcy estate of Energy XXI GOM, LLC and Cox Operating L.L.C. (the “Cox Trustee”) to acquire the necessary midstream infrastructure, which is expected to allow us to return the Main Pass 108 and 98 fields to production in the second quarter of 2025. Following developments in connection with the acquisition of the midstream infrastructure, on February 25, 2025, we mutually terminated the purchase agreement with the Cox Trustee and entered into a new purchase agreement with the Cox Trustee including the midstream infrastructure and additional properties. The closing of the acquisitions contemplated by the purchase agreement and subsequent return to production are subject to our obtaining approval from the Bankruptcy Court for the Southern District of Texas, necessary governmental approvals and permits in connection with the acquisitions, in addition to customary closing conditions.
Previous report
SeeFinancial Statements and Supplementary Data – Note 19 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.
Previous report
In addition to the impact of volatile commodity prices on our operations, continuing inflation could also impact our sales margins and profitability. The United States has experienced a rise in inflation since October 2021. Inflation peaked during mid-2022 at 9.1% but the rate of inflation has been gradually declining since the second half of 2022 according to the Consumer Price Index (the “CPI”). The annual inflation rate for December 2024 was 2.9%, a decrease from the 3.4% rate for December 2023. However, the annual inflation rate of January 2025 was 3.0%, an increase from the 2.9% rate for December 2024. Beginning in September 2024, the Federal Reserve made three cuts to the target federal funds rate, bringing the target federal funds range down to 4.25% to 4.50%, easing monetary policy for the first time in four years due to progress in inflation moving sustainably toward 2%. The Summary of Economic Projections published by the Federal Reserve in December 2024 points to another 50 basis points of cuts in 2025. However, if inflation were to continue to rise again, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure price stability, including targeted federal funds rate increases, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could negatively impact our business.
Previous report
Since our operations are in the Gulf of America, we are particularly vulnerable to the effects of hurricanes on production and operations. Significant hurricane impacts include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.
Previous report
Our production was impacted due to precautionary shut-ins of facilities and evacuations associated with Hurricanes Francine, Helene and Rafael. For 2024, we estimate deferred production related to Hurricane Francine was approximately 132.8 MBoe and affected 35 fields, deferred production related to Hurricane Helene was approximately 17.2 MBoe and affected five fields and deferred production related to Hurricane Rafael was approximately 3.4 MBoe and affected three fields.
Previous report
Production downtime following these hurricanes was extended as a result of damage and power loss at third party downstream facilities, including oil terminals, natural gas processing plants and refineries, causing them to remain offline for several weeks. While our assets and infrastructure did not suffer significant damage during the storm, we incurred $1.1 million of unplanned costs for minor repairs and restoring production, as well as evacuating employees and contractors, as a result of the hurricane. These amounts are reflected in lease operating expense.
Previous report
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
Previous report
Production volumes decreased by 547 MBoe to 12,183 MBoe during 2024 compared to the same period in 2023, primarily due to deferred production of approximately 0.8 MMBoe at our Mobile Bay Properties, approximately 0.3 MMBoe from the shut-on of the MP 98 and 108 fields and approximately 0.2 MMBoe from the effects of Hurricanes Francine, Helene and Rafael. These decreases were partially offset by approximately 1.9 MMBoe of production from wells acquired in both the January 2024 and the September 2023 acquisitions.
Previous report
As a result of the derivative contracts we have on our anticipated natural gas production volumes through April 2028, we expect these activities to continue to impact net income based on fluctuations in market prices for natural gas.
Previous report
During 2024, other expense, net, was $18.1 million, compared to $5.6 million for 2023. During 2024 and 2023, other expense primarily consisted of $20.9 million and $6.2 million, respectively, of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of America properties, partially offset by fees paid by producers to tie into our subsea equipment at one of our wells.
Previous report
Income tax (benefit) expense
Previous report
Investing activities*–*Net cash used in investing activities for 2024 increased $36.6 million compared to 2023. This was primarily due to an increase of $53.3 million in acquisition of property interests, partially offset by a decrease of $4.5 million in investment in oil and natural gas properties and the purchase of the corporate aircraft during 2023.
Previous report
Financing activities* –*Net cash used in financing activities during 2024 decreased by $313.2 million compared to 2023. This was primarily due to the redemption of the $552.5 million principal amount outstanding of the 9.75% Notes in February 2023 partially offset by the net cash proceeds of $275.0 million received from the issuance of the 11.75% Notes in January 2023.
Previous report
We have grown by making strategic acquisitions of producing properties in the Gulf of America. We seek opportunities where we can exploit additional drilling projects and reduce costs. In January 2024, we closed on the acquisition of rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of America, among other assets, for $77.3 million, subject to customary purchase price adjustments. The transaction was funded with cash on hand. We also received a final settlement statement for our September 2023 acquisition of certain oil and natural gas producing assets in the central and eastern shelf region of the Gulf of America and recorded an additional $3.3 million of oil and natural gas properties.
Previous report
We entered into a drilling contract during 2023. As of December 31, 2024, we anticipate that rig preparation work will begin in the fourth quarter of 2025 and drilling will begin in March 2026. We expect the total obligation under the contract to be approximately $9.9 million.
Reworded paragraphs (36)
Previous wording
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 December 31, 2024, we held working interests in 52 offshore producing fields in federal and state waters (which include 45 fields in federal waters and seven in state waters). We currently have under lease approximately 646,200 gross acres (502,300 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,500 gross acres in Alabama state waters, 493,000 gross acres on the conventional shelf and approximately 147,700 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by our wholly-owned subsidiaries and through our proportionately consolidated interest in Monza Energy LLC.
Current wording
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 December 31, 2025, we held working interests in 49 offshore producing fields in federal and state waters (which include 42 fields in federal waters and seven in state waters). We currently have under lease approximately 624,700 gross acres (490,200 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, 477,200 gross acres on the conventional shelf and approximately 141,900 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by our wholly-owned subsidiaries and through our proportionately consolidated interest in Monza Energy LLC.
Previous wording
Termination of Credit Agreement and Entry into New Credit Agreement
Current wording
Termination of Legacy Credit Agreement and Entry into Credit Agreement
Previous wording
On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we terminated our Sixth Amended and Restated Credit Agreement (the “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.
Current wording
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 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 Credit Agreement matures on July 28, 2028.
Previous wording
The EIA published its latest Short-Term Energy Outlook in January 2025. The EIA expects downward oil price pressures over much of the next two years as they expect that global oil production will grow more than global oil demand. The EIA forecasts that the spot price for WTI oil will average $70.33 per barrel in 2025, 8% less than 2024, and then continue to fall another 11% to $62.50 per barrel in 2026. 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.
Current wording
The EIA published its latest Short-Term Energy Outlook in January 2026. The EIA expects oil prices to decline in 2026, as global oil production exceeds global oil demand, causing inventories to rise. The EIA forecasts that the spot price for WTI oil will average $52.25 per barrel in 2026, 20% less than the average price of $65.46 per barrel in 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.
Previous wording
The EIA expects the spot prices for Henry Hub natural gas to average $3.14 per MMBtu in 2025 and $3.97 per MMBtu in 2026, up from a historically low average of $2.19 per MMBtu in 2024. The EIA expects wholesale natural gas prices to increase because growth in demand, led by liquified natural gas exports, will outpace production growth and keep inventories in the next two years at or below their previous five-year averages.
Current wording
The EIA expects the spot prices for Henry Hub natural gas to average $3.46 per MMBtu in 2026, down 2% from the 2025 average of $3.53 per MMBtu, and average $4.59 per MMBtu in 2027. The EIA expects wholesale natural gas prices to increase due to growth in demand, led by expanding liquified natural gas exports, and more natural gas consumption in the electric power sector from growing demand for power in the commercial and industrial sectors.
Previous wording
In addition, our 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, we estimate deferred production was approximately 2.6 MMBoe, excluding the deferred production from the hurricanes.
Current wording
Our oil, NGLs and natural gas production can 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 2025, we estimate deferred production was approximately 2.5 MMBoe.
Previous wording
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, seeBusiness – 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.
Current wording
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, seeBusiness – 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.
Previous wording
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 out 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.
Current wording
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 our 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.
Previous wording
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 inDerivative (gain) loss, net in our Consolidated Statements of Operations.
Current wording
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 inDerivative gain, net in our Consolidated Statements of Operations.
Previous wording
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 million to $281.5 million in 2024 compared to $257.7 million in 2023. On a per Boe basis, lease operating expenses increased to $23.10 per Boe during 2024 compared to $20.24 per Boe during 2023. On a component basis, base lease operating expenses increased $30.2 million, facility maintenance expenses increased $7.9 million and hurricane repairs increased $1.0 million, These increases were partially offset by a decrease of $15.3 million in workover expenses.
Current wording
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 $17.3 million to $298.8 million in 2025 compared to $281.5 million in 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. On a component basis, base lease operating expenses increased $10.0 million, workover expenses increased $5.6 million and facility maintenance expenses increased $2.7 million. These increases were partially offset by a decrease of $1.0 million in hurricane repairs.
Previous wording
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 acquired in January 2024 and September 2023 partially offset by $6.1 million of reduced expenses from the abandonment work to shutdown certain of our fields.
Current wording
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 fields brought online during 2025 and increased repairs and maintenance in various fields, partially offset by a full 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.
Previous wording
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 decrease in workover expenses and the increase in facilities maintenance expenses were due to the timing and mix of projects undertaken.
Current wording
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 increases in workover expenses and facilities maintenance expenses were due to the timing and mix of projects undertaken.
Previous wording
Hurricane expenses consist of costs forminor repairs and restoring production, as well as evacuating employees and contractors incurred as a result of Hurricanes Francine, Helene and Rafael.
Current wording
Hurricane expenses consist of costs forminor repairs and restoring production, as well as evacuating employees and contractors incurred as a result of Hurricanes Francine, Helene and Rafael during 2024.
Previous wording
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 to $28.2 million in 2024 compared to $26.3 million in 2023, 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. These 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.
Current wording
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 decreased to $25.7 million in 2025 compared to $28.2 million in 2024, primarily due tohigher 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 Mobile Bay processing plant during 2024.
Previous wording
*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 increased $28.3 million for 2024 compared to 2023 primarily due to increases of $33.3 million from an increase 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 million from the decrease in production for 2024 compared with 2023. The DD&A rate increased to $11.74 per Boe in 2024 from $9.01 per Boe in 2023. The DD&A rate per Boe increased primarily as a result of a higher depreciable base due to our January 2024 acquisition, increases in capital expenditures, future development costs and capitalized ARO and lower proved reserves.
Current wording
*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 $26.6 million for 2025 compared to 2024 primarily due to $28.6 million from a decrease in the depletion rate per Mcfe offset by $2.0 million from the increase in production for 2025 compared with 2024. The DD&A rate decreased to $9.39 per Boe in 2025 from $11.74 per Boe in 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and a 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.
Previous wording
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 $32.4 million in 2024 compared to $29.0 million in 2023 primarily due to our acquisition in January 2024 and revisions to the estimates used in calculating the liability.
Current wording
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 primarily due to the increase in our ARO liability as a result of revisions to the estimates used in calculating the liability.
Previous wording
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, G&A expenses were $82.4 million compared to $75.5 million in 2023. The increase is primarily due to increases 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 million in non-recurring legal fees and (iii) $1.9 million in medical claims cost, partially offset by a $2.1 million decrease in short-term incentive compensation costs.
Current wording
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 2025, G&A expenses were $80.0 million compared to $82.4 million in 2024. The decrease is primarily due to adecrease of $4.6 million in non-recurring legal and professional fees, partially offset by a $2.0 million increase in share-based compensation costs.
Previous wording
Interest expense, net of interest income, decreased $4.2 million for 2024 compared with 2023 primarily due to decreases of $7.9 million from the redemption in February 2023 of our 9.75% Senior Second Lien Notes due 2023 and $1.9 million from the lower outstanding principal balance of the Term Loan, partially offset by $2.8 million incurred on the 11.75% Notes issued in late January 2023 and a $2.6 million decrease in interest income. *
Current wording
Interest expense, net of interest income, decreased $4.0 million for 2025 compared with 2024 primarily due to a decrease of $42.3 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $37.3 million incurred on the 10.75% Notes issued in late January 2025. *
Previous wording
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 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.
Current wording
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.
Previous wording
Our effective tax rates for 2024 and 2023 were 10.3% and 54.0%, respectively. These rates differed from the federal statutory rate of 21% primarily due to the impact of state income taxes, non-deductible compensation and adjustments to the valuation allowance on our deferred tax assets.
Current wording
Our effective tax rate for 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of 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 theimpact of state income taxes, non-deductible compensation and adjustments to the valuation allowance on our deferred tax assets.
Previous wording
We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of December 31, 2024, we had $109.0 million of available cash on handand $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. 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.
Current wording
We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of December 31, 2025, we had $140.6 million of available cash on handand $43.9 million available under our Credit Agreement, based on a borrowing base of $50.0 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.
Previous wording
The following table summarizes cash flows provided by (used in) by type of activity for the following periods (in thousands):
Current wording
The following table summarizes cash flows provided by (used in) each type of activity for the following periods (in thousands):
Previous wording
Operating activities* –*Net cash provided by operating activities for 2024 was $59.5 million, decreasing $55.8 million from 2023. This was primarily due to decreases of $37.6 million in net (loss) income adjusted for certain non-cash items and $18.2 million from changes in operating assets and liabilities. The decrease in net (loss) income adjusted for certain non-cash items was primarily related to a $7.4 million decrease in revenues andincreases in cash operating expenses, partially offset by a $13.5 million increase in derivative cash receipts. The decrease in operating assets and liabilitiesis 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.
Current wording
Net cash provided by operating activities for 2025 was $77.2 million, increasing $17.7 million from 2024. This was primarily due to an increase of $29.6 million from changes in operating assets and liabilities offset by a decrease of $11.9 million in net loss adjusted for certain non-cash items. The increase in operating assets and liabilitiesis 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 andincreases in cash operating expenses, partially offset by a $10.1 million increase in derivative cash receipts.
Previous wording
Our preliminary capital expenditure budget for 2025 has been established in the range of $34.0 million to $42.0 million, which excludes acquisitions. In our view of the outlook for 2025, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2025 and beyond 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.
Current wording
Our preliminary capital expenditure budget for 2026 has been established in the range of $19.5 million to $24.5 million, which excludes acquisitions. In our view of the outlook for 2026, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2026 and beyond 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.
Previous wording
Any future acquisitions are subject to the completion of satisfactory due diligence, the negotiation and resolution of significant legal issues, the negotiation, documentation and completion of mutually satisfactory definitive agreements among the parties, the consent of our lenders, our ability to finance the acquisition and approval of our board of directors. We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all.
Current wording
We have grown by making strategic acquisitions of producing properties in the Gulf of America. We seek opportunities where we can exploit additional drilling projects and reduce costs. Any future acquisitions are subject to the completion of satisfactory due diligence, the negotiation and resolution of significant legal issues, the negotiation, documentation and completion of mutually satisfactory definitive agreements among the parties, the consent of our lenders, our ability to finance the acquisition and approval of our board of directors. We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all.
Previous wording
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. During 2024, we paid $39.7 million related to these obligations. Our ARO estimates as of December 31, 2024 and 2023 were $548.8 million and $498.8 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, the timing and amount of actual expenditures could be substantially different than our estimates. See Part I, Item 1A.Risk Factors andFinancial Statements and Supplementary Data – Note 4 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.
Current wording
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. During 2025, we paid $36.8 million related to these obligations. Our ARO estimates as of December 31, 2025 and 2024 were $561.9 million and $548.8 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, the timing and amount of actual expenditures could be substantially different than our estimates. See Part I, Item 1A.Risk Factors andFinancial Statements and Supplementary Data – Note 3 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.
Previous wording
As of December 31, 2024, we have $399.1 million in aggregate principal amount of long-term debt outstanding, with $28.7 million in aggregate principal coming due over the next twelve months.
Current wording
As of December 31, 2025, we have $358.8 million in aggregate principal amount of long-term debt outstanding, with $8.8 million in aggregate principal amount coming due over the next twelve months.
Previous wording
For additional information about our long-term debt, see Part II, Item 8.Financial Statements and Supplementary Data – Note 5 – Debt andNote 19 – Subsequent Eventsof this Annual Report.
Current wording
For additional information about our long-term debt, see Part II, Item 8.Financial Statements and Supplementary Data – Note 4 – Debtof this Annual Report.
Previous wording
In November** **2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to holders of common stock. During 2024, we have paid cash dividends totaling approximately $6.0 million to holders of our common stock. 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. For additional information about our dividends, see Part II, Item 8.Financial Statements and Supplementary Data – Note 7 – Stockholders’ Equity and Note 19 – Subsequent Eventsof this Annual Report.
Current wording
During 2025, we declared cash dividends totaling approximately $6.4 million to holders of our common stock. 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. For additional information about our dividends, see Part II, Item 8.Financial Statements and Supplementary Data – Note 6 – Stockholders’ Equity and Note 18 – Subsequent Eventsof this Annual Report.
Previous wording
As of December 31, 2024, we had expected cash payments for estimated interest on our long-term debt of $10.1 million payable within the next twelve months and $10.2 million payable through the maturity dates of our long-term debt.
Current wording
As of December 31, 2025, we have expected cash payments for estimated interest on our long-term debt of $37.8 million payable within the next twelve months and $78.4 million payable through the maturity dates of our long-term debt.
Previous wording
As of December 31, 2024, we had obligations for estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment of $6.7 million payable in the next twelve months and $80.3 million through the estimated timing of the plugging and abandonment obligation occurs. The amounts are based on current market rates and conditions for these types of bonds and are subject to change. Excluded are potential increases in surety bond requirements which cannot be determined.
Current wording
As of December 31, 2025, we had obligations for estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment of $7.1 million payable in the next twelve months and $88.1 million through the estimated timing of the plugging and abandonment obligation occurs. The amounts are based on current market rates and conditions for these types of bonds and are subject to change. Excluded are potential increases in surety bond requirements which cannot be determined.
Previous wording
Additionally, we have obligations related to estimates of minimum quantities obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field of $0.6 million in the next twelve months and $1.0 million through the term of the contracts.
Current wording
Additionally, we have obligations related to estimates of minimum quantities obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field of $0.4 million in the next twelve months and $0.4 million through the term of the contracts.
Previous wording
An accounting policy is deemed to be critical if the nature of the estimate or assumption it incorporates is subject to a material level of judgment related to matters that are highly uncertain and changes in those estimates and assumptions are reasonably likely to materially impact our consolidated financial statements. These estimates reflect our best judgment about current, and for some estimates, future, economic and market conditions and their potential effects based on information available as of the date of these financial statements. Our most significant accounting policies are discussed inFinancial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K.
Current wording
An accounting policy is deemed to be critical if the nature of the estimate or assumption it incorporates is subject to a material level of judgment related to matters that are highly uncertain and changes in those estimates and assumptions are reasonably likely to materially impact our consolidated financial statements. These estimates reflect our best judgment about current, and for some estimates, future, economic and market conditions and their potential effects based on information available as of the date of these financial statements. Our most significant accounting policies are discussed inFinancial Statements and Supplementary Data – Note 1 – Basis of Presentation and Significant Accounting Policies under Part II, Item 8 in this Form 10-K.
Previous wording
Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices for oil, NGLs and natural gas, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2024, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.09 per Mcfe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.10 per Mcfe.
Current wording
Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices for oil, NGLs and natural gas, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2025, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.06 per Mcfe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.06 per Mcfe.
Previous wording
Using the first-day-of-the-month average for the 12-months ended December 31, 2024 of the WTI oil spot price of $76.32 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2024 of the Henry Hub natural gas price of $2.13 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2024. Additionally, a 10% reduction in PV-10 at December 31, 2024, while all other factors remained constant, would also not have generated an impairment.
Current wording
Using the first-day-of-the-month average for the 12-months ended December 31, 2025 of the WTI oil spot price of $66.01 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2025 of the Henry Hub natural gas price of $3.39 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2025. Additionally, a 10% reduction in PV-10 at December 31, 2025, while all other factors remained constant, would also not have generated an impairment.
Previous wording
As of December 31, 2024, we have federal net operating loss (“NOL”) carryforwards of $51.5 million that do not expire, state NOL carryforwards of $104.1 million that expire on various dates from 2026 through 2043 and interest expense limitation carryforwards that do not expire. We believe that it is more likely than not that the benefit from certain of these carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance of $29.2 million on the deferred tax assets related to these carryforwards. If our assumptions change and we determine that we will be able to realize these carryforwards, the tax benefits related to any reversal of the valuation allowance on deferred tax assets as of December 31, 2024 would be recognized as a reduction of income tax expense.
Current wording
As of December 31, 2025, we have federal net operating loss (“NOL”) carryforwards of $87.1 million that do not expire, state NOL carryforwards of $108.8 million that expire on various dates from 2038 through 2040 and interest expense limitation carryforwards of $117.5 million that do not expire. We believe that it is more likely than not that the benefit from certain of these carryforwards will not be realized. In recognition of this risk, we have provided a full
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
valuation allowance against the deferred tax assets related to these carryforwards. If our assumptions change and we determine that we will be able to realize these carryforwards, the tax benefits related to any reversal of the valuation allowance on deferred tax assets as of December 31, 2025 would be recognized as a reduction of income tax expense.
Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
On January 28, 2025, we issued $350.0 million of 10.75% Notes. The 10.75% Notes were issued at par and mature on February 1, 2029. We also terminated the Credit Agreement and used the net proceeds from the issuance of the 10.75% Notes and cash on hand to repay in full all outstanding amounts owed under the Term Loan and the 11.75% Notes outstanding.
Previous report — wording carried elsewhere
On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we 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.