W&T OFFSHORE INC
For the period ended Jun 30, 2025. Filed Aug 5, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2025 · Filed Aug 5, 2025
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-Q
Period ended 2025-03-31; filed 2025-05-07.
0001558370-25-006597
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-06-30; filed 2025-08-05.
0001558370-25-010175
Item 2. 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 84 previous paragraphs and 91 current paragraphs.
40 unchanged; 25 reworded; 12 added; 18 removed; 1 previous and 14 current paragraphs rearranged.
Tables are not compared: 10 previous and 14 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 (12)
Current report
On June 14, 2025, we entered into the Settlement Agreements, by and between us and PIIC to dismiss all claims 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 our 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 our affiliates or subsidiaries; (c) there is an initiation of an insolvency proceeding for us or any of our 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.
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, which is expected to be upheld, would effectively nullify all current collateral requests 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
On July 4, 2025, the OBBBA was signed into law which, among other things, modified tax legislation affecting bonus depreciation rules and interest deductions. Specifically, the OBBBA provides for 100% bonus depreciation for property acquired and placed in service after January 19, 2025, and the use of earnings before income taxes, depreciation and amortization, rather than earnings before income taxes, with no phase-out for purposes of calculating the interest limitation for taxable years beginning after 2024. The OBBBA has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. We are currently evaluating the effects of these changes and other provisions of this legislation on our condensed consolidated financial statements, and we currently expect that the OBBBA will have a favorable impact our current tax expense and valuation allowance positions due to the increased depreciation and interest expense deductions allowed under the OBBBA.
Current report
We are also monitoring the impact of the tariffs announced by the United States federal government in 2025. 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 2025.
Current report
Production volumes decreased by 125 MBoe to 3,052 MBoe during the three months ended June 30, 2025 compared to the same period in 2024 primarily related to low gas availability in one of our fields, a shut-in of another field due to solids production in one of the wells and a temporary curtailment of some of our Mobile Bay field for unplanned pipeline maintenance, partially offset by restoring production at our West Delta 73, Main Pass 98 and Main Pass 108 fields.
Current report
Other expense, net* –*Other expense, net increased $12.2 million for the three months ended June 30, 2025 compared to the same period in 2024 primarily related to an increase in the accrual of additional expenses for net abandonment obligations related to the Company’s assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or may not be able to perform required abandonment obligations.
Current report
Six Months Ended June 30, 2025 Compared to the Six Months Ended June 30, 2024
Current report
Revenues
Current report
Operating Expenses
Current report
Base lease operating expenses increased primarily due to the restart of production in our West Delta 73, Main Pass 98 and Main Pass 108 fields partially offset by higher contract processing credits at Heidelberg due to a new platform processor.
Current report
Other Income and Expense Items
Current report
Other expense, net* –*Other expense, net increased $6.7 million for the three months ended June 30, 2025 compared to the same period in 2024 primarily related to an increase in the accrual of additional expenses for net abandonment obligations related to the Company’s assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or may not be able to perform required abandonment obligations.
Removed paragraphs (18)
Previous report
In January 2025, we received approximately $11.9 million for the sale of a non-core interest in our Garden Banks Blocks 385 and 386. In addition, we received $58.5 million related to the settlement of insurance claims from our Mobile Bay plant turnaround in February 2023. Because we use the full cost method of accounting, these amounts were included in our full cost pool at the time of receipt.
Previous report
Debt Refinancing
Previous report
Issuance of the 10.75% Notes
Previous report
On January 28, 2025, we issued and sold $350.0 million in aggregate principal amounts of our 10.75% Notes. The 10.75% Notes mature on February 1, 2029 and interest is payable on each February 1 and August 1, commencing August 1, 2025. The 10.75% Notes are guaranteed by the Guarantors. The 10.75% Notes are secured by second priority liens (subject to permitted liens and certain other exceptions) on substantially all of our oil and natural gas properties, including those of the Guarantors.
Previous report
We used the net proceeds from the issuance of the 10.75% Notes, along with cash on hand, to (i) purchase for cash such of our 11.75% Notes that were validly tendered pursuant to the terms of the Tender Offer; (ii) repay the $114.2 million of outstanding amounts under Term Loan; (iii) fund the full redemption amount for an August 1, 2025 redemption of the remaining 11.75% Notes not validly tendered and accepted for purchase in the Tender Offer; and (iv) pay any premiums, fees and expenses relating to these transactions.
Previous report
Redemption of the 11.75% Notes
Previous report
On January 13, 2025, we commenced the Tender Offer for any and all of our outstanding 11.75% Notes. On January 28, 2025, we accepted and purchased $269.7 million aggregate principal amount of the outstanding 11.75% Notes for a purchase price equal to $1,036.25 for each $1,000 principal amount of the Notes purchased. An additional $89,000 of Notes were tendered on February 12, 2025. We purchased these Notes for $89,905 plus accrued interest.
Previous report
After giving effect to this purchase, an aggregate $5.2 million principal amount of the 11.75% Notes remained outstanding. We then effected a legal defeasance of the 11.75% Notes by purchasing $5.9 million of government securities to cover the principal and interest due for those remaining 11.75% Notes. This process released us from our remaining obligations under the indenture governing the 11.75% Notes.
Previous report
Credit Agreement
Previous report
On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we terminated our prior credit agreement and entered into a new credit agreement which provides us with 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 Facility matures on July 28, 2028.
Previous report
Regulatory Update
Previous report
The change of Presidential administration in the early part of 2025 saw promising developments in the oil and natural gas regulatory environment. On January 20, 2025, President Trump issued Executive Order 14154,Unleashing American Energy. Section 3 of that Order directed heads of agencies to review existing regulations to identify agency actions that impose an undue burden on the identification, development, or use of domestic energy resources. The Trump administration also issued Executive Order 14156,Declaring a National Energy Emergency, stating that the United States’ insufficient energy production, transportation, refining and generation constituted an unusual and extraordinary threat to the nation’s economy, national security, and foreign policy. Furthermore, on February 3, 2025, Secretary Burgum issued Secretarial Order 3418,Unleashing American Energy. Section 4(b) of that Order directed agency officials to prepare an action plan that will include steps to suspend, revise, or rescind certain regulations.
Previous report
As it pertains to us, on April 8, 2025, pursuant to the above directives from the Trump administration, the Department of Interior, 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 co-owner or predecessor in title and meet other conditions.
Previous report
While we view this as a positive development, the substance and timing of future legal and regulatory actions cannot be predicted at this time. Additionally, regardless of any changes that may come as a result of the Secretarial Order, the 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 our 2024 Annual Report.
Previous report
In addition, the Trump administration has issued a number of executive orders aimed at streamlining regulations and reducing the regulatory burden on oil and natural gas companies, increasing federal oil and natural gas leasing, including in the Gulf of America, and expediting U.S. natural resource development.
Previous report
Henry Hub spot prices will average $4.27 per MMBtu in 2025 and $4.60 in 2026. The EIA is expecting natural gas prices to rise in 2025 as natural gas demand (consumption plus exports) in the United States will grow by 4% in 2025 compared with 2024, led by an 18% increase in exports of natural gas by pipeline and as liquified natural gas (“LNG”) and a 9% increase in residential and commercial consumption for space heating. The increase in natural gas exports is driven primarily by an increase in LNG exports as two new LNG export facilities ramp up operations.
Previous report
Other (income) expense, net* –*Other (income) expense, net increased $5.5 million for the three months ended March 31, 2025 compared to the same period in 2024 primarily related to a decrease in the accrual of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of America properties.
Previous report
We also paid dividends of $1.5 million in both the three months ended March 31, 2025 and 2024.
Reworded paragraphs (25)
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 March 31, 2025, we hold working interests in 52 producing offshore fields in federal and state waters (which include 45 fields in federal waters and seven in state waters). We currently have under lease approximately 634,700 gross acres (496,900 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, 487,200 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.
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 June 30, 2025, we hold working interests in 50 producing offshore fields in federal and state waters (which include 43 fields in federal waters and seven in state waters). We currently have under lease approximately 629,700 gross acres (491,900 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, 482,200 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.
Previous wording
See Part I, Item 1.Financial Statements – Note 4 – Debt of this Quarterly Report and Part II, Item 8.Financial Statements and Supplementary Data, in our 2024 Annual Report for additional information about the above debt transactions.
Current wording
For additional information about the bonding dispute and the associated Sureties Litigation, see Part I, Item 1.Financial Statements – Note 5 – Commitments and Contingencies of this Quarterly Report and Part II, Item 8.Financial Statements and Supplementary Data, in our 2024 Annual Report.
Previous wording
On May 6, 2025, we declared a regular quarterly dividend of $0.01 per share for the second quarter of 2025. We expect to pay the dividend on May 27, 2025 to stockholders of record as of the close of business on May 20, 2025.
Current wording
On August 4, 2025, we declared a regular quarterly dividend of $0.01 per share for the third quarter of 2025. We expect to pay the dividend on August 25, 2025 to stockholders of record as of the close of business on August 18, 2025.
Previous wording
The Energy Information Administration (“EIA”) published its latest Short Term Energy Outlook in April 2025. Oil prices fell sharply in the first week of April 2025 as oil market participants assessed announcements that the United States would impose new tariffs and OPEC+ would accelerate production increases. These announcements increase the likelihood that global oil inventories will rise in the coming month and have the potential to put further downward pressure on oil prices. As a result, the EIA is forecasting that the spot price for WTI oil will fall from an average of $71.84 per barrel for the first quarter of 2025 to an average of $61.33 per barrel for the remainder of 2025 and then continue to fall to an average of $57.50 per barrel in 2026.
Current wording
The Energy Information Administration (“EIA”) published its latest Short Term Energy Outlook in July 2025. The EIA is expecting rising global oil inventories will cause oil prices to fall from an average of $64.63 per barrel for the second quarter of 2025 to an average of $62.33 per barrel for the remainder of 2025 and then continue to fall to an average of $54.83 per barrel in 2026. The EIA is also forecasting that Henry Hub spot prices are expected to average $3.68 per MMBtu for the remainder of 2025 and $4.41 per MMBtu in 2026. The EIA is expecting that natural gas production will fall slightly in 2026, while liquified natural gas (“LNG”) exports will continue to increase, driven primarily by an increase in LNG exports as two new LNG export facilities ramp up operations.
Previous wording
The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for the three months ended March 31, 2025 and 2024 (in thousands, except average realized sales prices data):
Current wording
The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for the periods presented and corresponding changes (in thousands, except average realized sales prices data):
Previous wording
Lease operating expenses* –*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, were relatively flat during the three months ended March 31, 2025 compared to the same period in 2024. On a per Boe basis, lease operating expenses increased to $25.88 per Boe during the three months ended March 31, 2025 compared to $22.14 per Boe during the three months ended March 31, 2024. On a component basis, base lease operating expenses decreased $3.4 million, workover expenses decreased $1.0 million and facilities maintenance expense increased $4.5 million.
Current wording
Lease operating expenses* –*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 by $2.9 million during the three months ended June 30, 2025 compared to the same period in 2024. On a component basis, base lease operating expenses increased $2.2 million, workover expenses increased $1.8 million and facilities maintenance expense decreased $1.1 million.
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 decreased primarily due to higher contract processing credits at Heidelberg due to a new platform processor and reduced operating expenses related to the decrease in production volumes.
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 the restart of production in our West Delta 73, Main Pass 98 and Main Pass 108 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 increase in workover expenses and the decrease in facilities maintenance expenses were due to the timing and mix of projects undertaken.
Previous wording
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 decreased $1.9 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 primarilydue to decreases of $1.7 million in gathering and transportation expenses and $0.2 million in production taxes. Gathering and transportation expenses decreased primarily due to lower production volumes in the three months ended March 31, 2025 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 Mobile Bay processing plant in the three months ended March 31, 2024.
Current wording
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 decreased $3.1 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 primarilydue to a decrease of $3.3 million in gathering and transportation expenses offset by an increase of $0.2 million in production taxes. Gathering and transportation expenses decreased primarily due to lower production volumes in the three months ended June 30, 2025 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 Mobile Bay processing plant in the three months ended June 30, 2024.
Previous wording
*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&Adecreased $1.0 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024 primarily due to $5.3 million from the decrease in production partially offset by $4.2 million from an increase in the depletion rate per Mcfe. The DD&A rate increased to $11.99 per Boe for the three months ended March 31, 2025 from $10.61 per Boe for the three months ended March 31, 2024. The DD&A rate per Boe increased primarily as a result of increases in future development costs and capitalized ARO, partially offset by a lower depreciable base and 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.
Current wording
*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&Adecreased $10.2 million for the three months ended June 30, 2025 as compared to the three months ended June 30, 2024 primarily due to decreases of $9.1 million from the decrease in the depletion rate per Mcfe and $1.1 million for the decrease in production. The DD&A rate per Boedecreased to $8.67 per Boe for the three months ended June 30, 2025 from $11.55 per Boe for the three months ended June 30, 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, a lower depreciable base and 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
Asset retirement obligations accretion expense *–*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 $0.4 million in the three months ended March 31, 2025 compared to the same period in 2024 primarily due to the increase in our ARO liability as a result of revisions to the estimates used in calculating the liability.
Current wording
Asset retirement obligations accretion expense *–*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 was relatively flat in the three months ended June 30, 2025 compared to the same period in 2024.
Previous wording
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 decreased $0.4 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. The decrease is primarily due to decreases of (i) $0.9 million in share-based compensation costs and (ii) $0.9 million in employee benefit costs due to lower medical claims costs, partially offset by a $1.6 million increase in legal fees related to various litigation issues, such as our sureties litigation.
Current wording
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 decreased $3.7 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024. The decrease is primarily due to a decrease of $4.7 million in non-recurring legal and professional fees, partially offset by an increase of $1.5 million in share-based compensation costs.
Previous wording
Interest expense, net* –*Interest expense, net, decreased $0.6 million for the three months ended March 31,2025 compared to the same period in 2024 primarily due to a decrease of $7.6 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $6.6 million incurred on the 10.75% Notes issued in late January 2025.
Current wording
Interest expense, net* –*Interest expense, net, decreased $1.2 million for the three months ended June 30, 2025 compared to the same period in 2024 primarily due to a decrease of $10.9 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $9.9 million incurred on the 10.75% Notes issued in late January 2025.
Previous wording
Derivative loss (gain), net* –*During the three months ended March 31, 2025, we recorded a $2.7 million derivative loss for our natural gas derivative contracts consisting of $0.9 million of unrealized gain from the increase in the fair value of our open natural gas contracts offset by $3.6 million of realized losses. During the three months ended March 31, 2024, we recorded a $4.9 million derivative gainfor our natural gas derivative contracts consisting of $1.1 million of unrealized gains from the increase in the fair value of our open natural gas contracts and $3.8 million of realized gains.
Current wording
Derivative (gain) loss, net* –*During the three months ended June 30, 2025, we recorded a $12.0 million derivative gain for our derivative contracts consisting of $2.5 million of unrealized gain from the increase in the fair value of our open contracts and $9.5 million of realized gains, which included$4.3 million related to the monetization of our natural gas put contracts. During the three months ended June 30, 2024, we recorded a $2.4 million derivative lossfor our natural gas derivative contracts consisting of $2.7 million of unrealized loss from the decrease in the fair value of our open natural gas contracts offset by $0.3 million of realized gains.
Previous wording
Income tax (benefit) expense* –*Our effective tax rates for the three months ended March 31, 2025 and 2024 was 13.1% and (10.0)%, respectively. The difference between the effective tax rate and the federal statutory rate was primarily due to the impact of nondeductible compensation and adjustments to the valuation allowance.
Current wording
Income tax benefit* –*Our effective tax rates for the three months ended June 30, 2025 and 2024 was 10.2% and 23.1%, respectively. The difference between the effective tax rate and the federal statutory rate was primarily due to the impact of nondeductible compensation and adjustments to the valuation allowance.
Previous wording
Production volumes decreased by 0.5 MMBoe to 2.7 MMBoe during the three months ended March 31, 2025 compared to the same period in 2024 primarily related to deferred production ofapproximately 0.2 MMBoe at our Mobile Bay properties related to freezing weather and compressor issues and approximately 0.2 MMBoe from the shut-ins of our West Delta 73 field and our Main Pass 98 and 108 fields.
Current wording
Production volumes decreased by 580 MBoe to 5,796 MBoe during the six months ended June 30, 2025 compared to the same period in 2024 primarily related to low gas availability in one of our fields, a shut-in of another field due to solids production in one of the wells and deferred productionat our Mobile Bay properties related to freezing weather and compressor issues, partially offset by restoring production at our West Delta 73, Main Pass 98 and Main Pass 108 fields.
Previous wording
Loss on extinguishment of debt* –During the three months ended March 31, 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 wording
Loss on extinguishment of debt* –During the six months ended June 30, 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.
Previous wording
We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of March 31, 2025, we had $105.9 million of unrestricted cash on hand and $50.0 million available under our New Credit Agreement. 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.
Current wording
We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of June 30, 2025, we had $120.7 million of unrestricted cash on hand and $50.0 million available under our New Credit Agreement. 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.
Previous wording
Net cash provided by operating activities decreased $14.8 million in the three months ended March 31, 2025 compared to the corresponding period in 2024. This was primarily due to decreases of $12.4 million in net loss adjusted for certain noncash items and $2.4 million in operating cash flows from changes in operating assets and liabilities. The decrease in net loss adjusted for certain noncash items was primarily related to a $10.9 million decrease in revenues and a $7.9 million unfavorable change in derivative settlements and receipts, partially offset by decreases in cash operating expenses. The decrease in operating assets and liabilitiesis primarily related to higher accounts receivable offset by lower accounts payable and accrued liabilities balances in the current period.
Current wording
Net cash provided by operating activities decreased $24.3 million in the six months ended June 30, 2025 compared to the corresponding period in 2024. This was primarily due to a decrease of $33.2 million in net loss adjusted for certain noncash items offset by an increase of $8.9 million in operating cash flows from changes in operating assets and liabilities. The decrease in net loss adjusted for certain noncash items was primarily related to a $31.3 million decrease in revenues and a $2.0 million unfavorable change in derivative settlements and receipts, partially offset by decreases in cash operating expenses. The decrease in operating assets and liabilitiesis primarily related to higher ARO settlements and unfavorable changes in accounts payable and accrued liabilities offset by favorable changes in accounts receivable.
Previous wording
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 provided by (used in) investing activities were $63.3 million and $(87.6) million, respectively. During the three months ended March 31, 2024, we paid $80.5 million related to our January 2024 acquisition and our September 2023 acquisition. Investments in oil and natural gas properties were $6.7 million and $7.1 million during the three months ended March 31, 2025 and 2024, respectively. During the three months ended March 31, 2025, we also 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.
Current wording
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 provided by (used in) investing activities were $52.5 million and $(94.4) million, respectively. During the six months ended June 30, 2024, we paid $80.6 million related to our January 2024 acquisition and our September 2023 acquisition. Investments in oil and natural gas properties were $17.1 million and $13.7 million during the six months ended June 30, 2025 and 2024, respectively. During the six
Previous wording
Cash flows used in financing activities were $63.1 million and $2.5 million for three months ended March 31, 2025 and 2024, 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 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 $5.9 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.
Current wording
Cash flows used in financing activities were $65.6 million and $4.7 million for the six months ended June 30, 2025 and 2024, 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 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 $5.9 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.
Previous wording
As of March 31, 2025, we expect to incur an additional $25.0 million to $33.0 million of capital expenditures in the remainder of 2025, which excludes acquisitions. In our view of the outlook for the remainder of 2025, we believe this 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.
Current wording
As of June 30, 2025, we expect to incur an additional $15.0 million to $23.0 million of capital expenditures in the remainder of 2025, which excludes acquisitions. In our view of the outlook for the remainder of 2025, we believe this 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.
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. Through the three months ended March 31, 2025, we have paid $3.8 million related to these obligations. Our ARO estimates as of March 31, 2025 and December 31, 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, actual expenditures could be substantially different than our estimates. See Part I, Item 1A.Risk Factors, of our 2024 Annual Report for additional information.
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. Through the six months ended June 30, 2025, we have paid $16.0 million related to these obligations. Our ARO estimates as of June 30, 2025 and December 31, 2024 were $556.8 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, actual expenditures could be substantially different than our estimates. See Part I, Item 1A.Risk Factors, of our 2024 Annual Report for additional information.
Previous wording
As of March 31, 2025, we have $359.7 million in aggregate principal amount of long-term debt outstanding, with $1.1 million in aggregate principal coming due over the next twelve months.
Current wording
As of June 30, 2025, we have $359.4 million in aggregate principal amount of long-term debt outstanding, with $1.1 million in aggregate principal coming due over the next twelve months.
Previous wording
During the three months ended March 31, 2025, we paid a cash dividend of approximately $1.5 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.
Current wording
During the six months ended June 30, 2025, we paid cash dividends of $3.0 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.
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Current report — wording carried from elsewhere
The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for the periods presented and corresponding changes (in thousands, except average realized sales prices data):
Current report — wording carried from elsewhere
Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between the six months ended June 30, 2025 and 2024 (in thousands):
Current report — wording carried from elsewhere
The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes (in thousands, except average data):
Current report — wording carried from elsewhere
Lease operating expenses* –*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 $3.1 million during the six months ended June 30, 2025 compared to the same period in 2024. On a per Boe basis, lease operating expenses increased to $25.52 per Boe during the six months ended June 30, 2025 compared to $22.71 per Boe during the six months ended June 30, 2024. On a component basis, base lease operating expenses decreased $1.2 million, workover expenses increased $0.8 million and facilities maintenance expense increased $3.5 million.
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
Gathering, transportation and production taxes* –*Gathering, transportation and production taxes decreased $5.0 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 primarilydue to a decrease of $5.0 million in gathering and transportation expenses. Gathering and transportation expenses decreased primarily due to lower production volumes in the six months ended June 30, 2025 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 Mobile Bay processing plant in the six months ended June 30, 2024.
Current report — wording carried from elsewhere
*Depreciation, depletion and amortization –*D&Adecreased $11.3 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to decreases of $5.8 million from the decrease in production and $5.5 million from the decrease in the depletion rate per Mcfe. The DD&A rate decreased to $10.24 per Boe for the six months ended June 30, 2025 from $11.07 per Boe for the six months ended June 30, 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, a lower depreciable base and 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.
Current report — wording carried from elsewhere
Asset retirement obligations accretion expense *–*Accretion expense increased $0.7 million in the six months ended June 30, 2025 compared to the same period in 2024 primarily due to the increase in our ARO liability as a result of revisions to the estimates used in calculating the liability.
Current report — wording carried from elsewhere
General and administrative expenses* –*G&A expenses decreased $4.0 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. The decrease is primarily due to decreases of $3.7 million in non-recurring legal and professional fees and $1.7 million in employee benefit costs due to lower medical claims costs, partially offset by a $0.5 million increase in share-based compensation costs.
Current report — wording carried from elsewhere
The following table presents the components of other income and expense items for the periods presented and corresponding changes (in thousands):
Current report — wording carried from elsewhere
Interest expense, net* –*Interest expense, net, decreased $1.7 million for the six months ended June 30,2025 compared to the same period in 2024 primarily due to a decrease of $18.2 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $16.5 million incurred on the 10.75% Notes issued in late January 2025.
Current report — wording carried from elsewhere
Derivative (gain) loss, net* –*During the six months ended June 30, 2025, we recorded a $9.3 million derivative gain for our derivative contracts consisting of $3.4 million of unrealized gain from the increase in the fair value of our open natural gas contracts and $5.9 million of realized gains, which included$4.3 million related to the monetization of our natural gas put contracts. During the six months ended June 30, 2024, we recorded a $2.5 million derivative gainfor our natural gas derivative contracts consisting of $1.6 million of unrealized loss from the decrease in the fair value of our open natural gas contracts offset by $4.1 million of realized gains.
Current report — wording carried from elsewhere
Income tax benefit* –*Our effective tax rates for the six months ended June 30, 2025 and 2024 was 12.0% and 11.8%, respectively. The difference between the effective tax rate and the federal statutory rate was primarily due to the impact of nondeductible compensation and adjustments to the valuation allowance.
Current report — wording carried from elsewhere
months ended June 30, 2025, we also 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.
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Previous report — wording carried elsewhere
The EIA is forecasting that Henry Hub spot prices are expected to average more than $3.93 per MMBtu in the second quarter of 2025, an 88% increase compared with the second quarter of 2024. The EIA is also forecasting that