W&T OFFSHORE INC
For the period ended Jun 30, 2026. Filed Aug 5, 2026.
View on SEC.govAbout this filing
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, 2026 · Filed Aug 5, 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-Q
Period ended 2026-03-31; filed 2026-05-07.
0001104659-26-057242
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-06-30; filed 2026-08-05.
0001104659-26-091281
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 66 previous paragraphs and 84 current paragraphs.
41 unchanged; 21 reworded; 9 added; 3 removed; 1 previous and 13 current paragraphs rearranged.
Tables are not compared: 13 previous and 17 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 (9)
Current report
On June 18, 2026, the United States and Iran signed a memorandum of understanding (“MOU”) related to the conflict between the two countries, including with respect to the re-opening of the Strait of Hormuz, which had been closed earlier in 2026 and had contributed to elevated oil prices. Expectations of increasing oil supply and moderating inventory draws have caused oil prices to fall. The average spot price for WTI oil averaged $84.81 per barrel in June 2026, down $17.32 per barrel from May 2026. In the Energy Information Administration’s (the “EIA”) Short-Term Energy Outlook published in July 2026, the EIA is forecasting that spot prices for WTI will average $68.50 per barrel for the remainder of 2026 and $60.83 per barrel in 2027. The EIA expects that ongoing oil inventory accumulation over the next year will continue to put downward pressure on oil prices.
Current report
Just over a week after signing the MOU, Iran launched a drone strike against a ship in the Strait of Hormuz. The attack, interpreted by the United States as a violation of the ceasefire agreement, prompted a round of contained strikes against Iran. In addition, Yemen’s Houthis opened a new front in the war by targeting vessels carrying Saudi oil, further disrupting global oil shipping as the Red Sea is another strategic waterway that oil companies use to transport their oil from the Middle East. Although oil prices rose as a result of these disruptions, prices are still significantly lower than the high prices experienced in the middle of May 2026. Workarounds via pipelines and the use of the southern shipping route through the Strait of Oman have kept the cost of oil from skyrocketing, and production worldwide has also stepped up in response to the off-and-on closure of the Strait of Hormuz.
Current report
Production volumes increased by 105 MBoe to 3,157 MBoe during the three months ended June 30, 2026 compared to the same period in 2025 primarily due to restoring production at our West Delta 73 and Eugene Island 64 fields and recompletion of a well at our Garden Banks 783 field, partially offset by reduced production at our Mobile Bay fields due to a temporary re-route of production due to third-party maintenance.
Current report
Other expense, net* –*Other expense, net decreased $13.2 million for the three months ended June 30, 2026 compared to the same period in 2025 primarily related to an accrual of additional expenses in the three months ended June 30, 2025 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 may not be able to perform required abandonment obligations.
Current report
Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025
Current report
Revenues
Current report
Operating Expenses
Current report
Other Income and Expense Items
Current report
Other expense, net* –*Other expense, net decreased $12.0 million for the six months ended June 30, 2026 compared to the same period in 2025 primarily related to an accrual of additional expenses in the six months ended June 30, 2025 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 may not be able to perform required abandonment obligations.
Removed paragraphs (3)
Previous report
The Energy Information Administration (the “EIA”) published its latest Short-Term Energy Outlook in April 2026. Global oil markets are in a period of heightened volatility and uncertainty due to significant disruption to shipping through the Strait of Hormuz since the conflict with Iran began at the end of February 2026. The WTI oil spot price averaged $91.38 per barrel in March 2026, $26.87 per barrel higher than the average for February 2026. The conflict with Iran has quickly shifted market dynamics, as producers in the region have been forced to shut-in significant volumes of oil production, leading to near-term tightness in the market. In its forecast, the EIA is forecasting that the average spot price for WTI oil will peak in the second quarter of 2026 at $101.67 per barrel before easing as production shut-ins slowly abate. The EIA is forecasting that the spot price for WTI oil will average $92.11 per barrel for the remainder of 2026 and $72.58 per barrel in 2027.
Previous report
We are also monitoring the impact of the tariffs imposed by the United States federal government. 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 our capital expenditures or operating expenses in 2026.
Previous report
We will continue to monitor developments related to trade policy and assess any potential impacts on our operations and cost structure.
Reworded paragraphs (21)
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, 2026, we hold working interests in 48 producing offshore fields in federal and state waters (which include 41 fields in federal waters and seven in state waters). We currently have under lease approximately 605,200 gross acres (471,300 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,600 gross acres in Alabama state waters, 457,700 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, 2026, we hold working interests in 48 offshore fields in federal and state waters (which include 41 fields in federal waters and seven in state waters). We currently have under lease approximately 591,000 gross acres (457,100 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,600 gross acres in Alabama state waters, 449,200 gross acres on the conventional shelf and approximately 136,200 gross acres in the deepwater. A majority of our daily production is derived from wells we operate.
Previous wording
On May 7, 2026, we declared a regular quarterly dividend of $0.01 per share of common stock for the second quarter of 2026. We expect to pay the dividend on May 28, 2026 to stockholders of record as of the close of business on May 21, 2026.
Current wording
On August 5, 2026, we declared a regular quarterly dividend of $0.01 per share of common stock for the third quarter of 2026. We expect to pay the dividend on August 26, 2026 to stockholders of record as of the close of business on August 19, 2026.
Previous wording
The Henry Hub spot price averaged $4.80 per MMBtu for the first quarter of 2026, and the EIA expects the spot prices for Henry Hub natural gas to average $3.29 per MMBtu for the remainder of 2026 and average $3.59 per MMBtu in 2027. The EIA expects wholesale natural gas prices to remain close to recent seasonal norms as natural gas storage levels remain at average levels.
Current wording
The Henry Hub spot price averaged $2.95 per MMBtu for the second quarter of 2026, and the EIA expects the spot prices for Henry Hub natural gas to average $3.47 per MMBtu for the remainder of 2026 and average $3.49 per MMBtu in 2027. The EIA expects that record natural gas production will help meet rising demand from the electric power sector, putting moderate downward pressure on natural gas prices.
Previous wording
Our average realized sales price for oil and natural gas differs from the WTI average price and the NYMEX Henry Hub average price, respectively, primarily due to premiums or discounts, quality adjustments, location adjustments and volume weighting (collectively referred to as differentials). Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation. Natural gas price differentials are strongly impacted by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products which are used as feedstock.
Current wording
Our average realized sales price for oil and natural gas differs from the WTI average price and the NYMEX Henry Hub average price, respectively, primarily due to premiums or discounts, quality adjustments, location adjustments and volume weighting (collectively referred to as differentials). Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation. Natural gas price differentials are strongly impacted by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price
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, net in our Condensed 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 loss (gain), net in our Condensed Consolidated Statements of Operations.
Previous wording
Lease operating expenses* –*Lease operating expenses (“LOE”) include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, insurance premiums, workover costs and facility maintenance expenses. LOE, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, decreased $4.9 million during the three months ended March 31, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $20.29 per Boe during the three months ended March 31, 2026 compared to $25.88 per Boe during the three months ended March 31, 2025. On a component basis, base LOE decreased $5.2 million, workover expenses decreased $0.7 million, facilities maintenance expense increased $1.1 million and hurricane repairs decreased $0.1 million.
Current wording
Lease operating expenses* –*Lease operating expenses (“LOE”) include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, insurance premiums, workover costs and facility maintenance expenses. LOE, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, decreased $5.4 million during the three months ended June 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $22.67 per Boe during the three months ended June 30, 2026 compared to $25.20 per Boe during the three months ended June 30, 2025. On a component basis, base LOE decreased $2.5 million, workover expenses decreased $1.1 million, facilities maintenance expense decreased $1.9 million and hurricane repairs increased $0.1 million.
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 increases in workover expenses and 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 decreases in workover expenses and 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 increased $3.0 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the three months ended March 31, 2026.
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 increased $1.1 million for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the three months ended June 30, 2026.
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&A decreased $5.6 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025 primarily due to a decrease of $11.6 million from the decrease in the depletion rate per thousand cubic feet equivalent offset by an increase of $6.0 million from the increase in production. The DD&A rate decreased to $8.37 per Boe for the three months ended March 31, 2026 from $11.99 per Boe for the three months ended March 31, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, partially offset by decreased proved reserves.
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&A decreased $0.9 million for the three months ended June 30, 2026 as compared to the three months ended June 30, 2025 primarily due to a decrease of $1.6 million from the decrease in the depletion rate per thousand cubic feet equivalent (“Mcfe”) offset by an increase of $0.9 million from the increase in production. The DD&A rate decreased to $8.10 per Boe for the three months ended June 30, 2026 from $8.67 per Boe for the three months ended June 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, partially offset by decreased proved reserves.
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 increased $4.7 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 primarily due to an increase of $5.4 million in share-based compensation costs, partially offset by a $1.0 million decrease in employee payroll costs.
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 increased $9.8 million for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 primarily due to increases of $8.2 million in share-based compensation costs and $1.1 million in legal and professional fees.
Previous wording
Derivative loss, net* –*During the three months ended March 31, 2026, we recorded a $24.5 million derivative loss for our derivative contracts consisting of $2.7 million of realized losses and$21.8 million of unrealized loss from the decrease in the fair value of our open contracts. During the three months ended March 31, 2025, we recorded a $2.7 million derivative lossfor our natural gas derivative contracts consisting of $3.6 million of realized losses offset by $0.9 million of unrealized gain from the increase in the fair value of our open contracts.
Current wording
Derivative loss (gain), net* –*During the three months ended June 30, 2026, we recorded a $1.9 million derivative loss for our derivative contracts consisting of $13.7 million of realized losses offset by $11.8 million of unrealized gain from the increase in the fair value of our open contracts. During the three months ended June 30, 2025, we recorded a $12.0 million derivative gainfor our natural gas derivative contracts consisting of $9.5 million of realized gains and $2.5 million of unrealized gain from the increase in the fair value of our open contracts.
Previous wording
Income tax expense (benefit)* –*Our effective tax rates for the three months ended March 31, 2026 and 2025 were (13.3)% and 13.1%, respectively, and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit and adjustments to the valuation allowance.
Current wording
Income tax benefit* –*Our effective tax rates for the three months ended June 30, 2026 and 2025 were (12.2)% and 10.2%, respectively, and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit and adjustments to the valuation allowance.
Previous wording
Production volumes increased by 515 MBoe to 3,259 MBoe during the three months ended March 31, 2026 compared to the same period in 2025 primarily due to restoring production at our West Delta 73, MO 916 and Main Pass 108 fields and increased production from our Mobile Bay fields due to reduced downtime, partially offset by shut-ins at our SS 349 field for approximately five days.
Current wording
Production volumes increased by 620 MBoe to 6,416 MBoe during the six months ended June 30, 2026 compared to the same period in 2025 primarily due to restoring production at our West Delta 73, Eugene Island 64, Mobile Bay 916 and Main Pass 108 fields and increased production from our Mobile Bay fields due to reduced downtime, partially offset by shut-ins at our SS 349 field for approximately five days.
Previous wording
We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of March 31, 2026, we had $130.9 million of unrestricted cash on hand and $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 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, 2026, we had $150.7 million of unrestricted cash on hand and $43.4 million available under our Credit Agreement, based on a borrowing base of $50.0 million and $6.6 million of letters of credit outstanding. We also have up to approximately $83.0 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth and will allow us to meet our cash requirements for at least the next 12 months and beyond.
Previous wording
Net cash provided by operating activities increased $5.7 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. This was primarily due to an increase of $25.5 million in net loss adjusted for certain noncash items and a decrease of $19.7 million in operating cash flows from changes in operating assets and liabilities. The increase in net loss adjusted for certain noncash items was primarily related to increases of $20.2 million in revenues and $5.6 million in derivative settlements. The decrease in operating assets and liabilitiesis primarily related to higher ARO settlements and unfavorable changes in accounts receivable, offset by favorable changes in accounts payable, accrued liabilities and other.
Current wording
Net cash provided by operating activities increased $11.1 million in the six months ended June 30, 2026 compared to the corresponding period in 2025. This was primarily due to an increase of $53.2 million in net loss adjusted for certain noncash items and a decrease of $42.1 million in operating cash flows from changes in operating assets and liabilities. The increase in net loss adjusted for certain noncash items was primarily related to increases of $60.4 million in revenues offset by an increase of $16.4 million in derivative settlements. The decrease in operating assets and liabilitiesis primarily related to higher ARO settlements and unfavorable changes in accounts receivable, accounts payable and accrued liabilities and other.
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 (used in) provided by investing activities were $(10.3) million and $63.3 million during the three months ended March 31, 2026 and 2025, respectively. Investments in oil and natural gas properties were $10.1 million and $6.7 million during the three months ended March 31, 2026 and 2025, respectively. During the three months ended March 31, 2025, we received $58.5 million in insurance proceeds and
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 (used in) provided by investing activities were $(19.0) million and $52.5 million during the six months ended June 30, 2026 and 2025, respectively. Investments in oil and natural gas properties were $18.8 million and $17.1 million during the six months ended June 30, 2026 and 2025, respectively. During the six months ended June 30, 2025, we received $58.5 million in insurance proceeds and $11.9 million in proceeds from the sale of oil and natural gas properties. As we use the full cost method of accounting for our oil and natural gas properties, these proceeds were recorded in our full cost pool.
Previous wording
Cash flows used in financing activities were $1.9 million and $63.1 million for the three months ended March 31, 2026 and 2025, respectively. In connection with our debt refinancing in January 2025, we received $350.0 million in proceeds from the issuance of our 10.75% Notes and used these proceeds, along with cash on hand, to (i) purchase for cash, pursuant to a tender offer, $269.8 million of our 11.75% Senior Second Lien Notes due 2026 (the “11.75% Notes”); (ii) repay $114.2 million of amount outstanding under the credit agreement of certain of our indirect, wholly-owned subsidiaries; (iii) purchase $5.9 million of government securities to be used in the legal defeasance of the remaining principal of our 11.75% Notes not validly tendered and accepted for purchase in the tender offer; and (iv) pay $21.3 million in premiums, fees and debt issuance costs.
Current wording
Cash flows used in financing activities were $6.8 million and $65.6 million for the six months ended June 30, 2026 and 2025, respectively. In connection with our debt refinancing in January 2025, we received $350.0 million in proceeds from the issuance of our 10.75% Notes and used these proceeds, along with cash on hand, to (i) purchase for cash, pursuant to a tender offer, $269.8 million of our 11.75% Senior Second Lien Notes due 2026 (the “11.75% Notes”); (ii) repay $114.2 million of amount outstanding under the credit agreement of certain of our indirect, wholly-owned subsidiaries; (iii) purchase $5.9 million of government securities to be used in the legal defeasance of the remaining principal of our 11.75% Notes not validly tendered and accepted for purchase in the tender offer; and (iv) pay $21.3 million in premiums, fees and debt issuance costs.
Previous wording
As of March 31, 2026, we expect to incur an additional $12.0 million to $18.0 million of capital expenditures in the remainder of 2026, which excludes acquisitions. In our view of the outlook for the remainder of 2026, we believe 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
In our view of the outlook for the remainder of 2026, we believe our expected level of capital expenditure will leave us with sufficient liquidity to operate our business, while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.
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, 2026, we have paid $17.2 million related to these obligations. Our ARO estimates as of March 31, 2026 and December 31, 2025 were $566.0 million and $561.9 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Part I, Item 1A.Risk Factors, of our 2025 Annual Report for additional information.
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, 2026, we have paid $20.6 million related to these obligations. Our ARO estimates as of June 30, 2026 and December 31, 2025 were $573.2 million and $561.9 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Part I, Item 1A.Risk Factors, of our 2025 Annual Report for additional information.
Previous wording
As of March 31, 2026, we have $358.6 million in aggregate principal amount of long-term debt outstanding, with $8.6 million in aggregate principal coming due over the next twelve months.
Current wording
As of June 30, 2026, we have $358.3 million in aggregate principal amount of long-term debt outstanding, with $8.3 million in aggregate principal coming due over the next twelve months.
Previous wording
During the three months ended March 31, 2026, we declared a cash dividend of $0.01 per share of common stock. The dividend was paid on March 26, 2026 to stockholders of record as of the close of business on March 19, 2026. The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors.
Current wording
During the six months ended June 30, 2026, we declared cash dividends of $3.2 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.
Rearranged current paragraphs (13)
Current report — wording carried from elsewhere
of oil while others are affected by natural gas prices as well as the demand for certain chemical products which are used as feedstock.
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, 2026 and 2025 (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* –*LOE decreased $10.3 million during the six months ended June 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $21.46 per Boe during the six months ended June 30, 2026 compared to $25.52 per Boe during the six months ended June 30, 2025. On a component basis, base LOE decreased $7.8 million, workover expenses decreased $1.7 million and facilities maintenance expense decreased $0.8 million.
Current report — wording carried from elsewhere
Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base LOE. These costs decreased primarily due to lower costs overall, reflecting the success of our cost reduction efforts that began in the fourth quarter of 2025 and continued into the six months ended June 30, 2026.
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 decreases 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 increased $4.1 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the six months ended June 30, 2026.
Current report — wording carried from elsewhere
*Depreciation, depletion and amortization –*DD&A decreased $6.5 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025 primarily due to a decrease of $12.5 million from the decrease in the depletion rate per Mcfe offset by an increase of $6.2 million from the increase in production. The DD&A rate decreased to $8.24 per Boe for the six months ended June 30, 2026 from $10.24 per Boe for the six months ended June 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, partially offset by decreased proved reserves.
Current report — wording carried from elsewhere
General and administrative expenses* –*G&A expenses increased $14.5 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 primarily due to an increase of $13.5 million 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
Derivative loss (gain), net* –*During the six months ended June 30, 2026, we recorded a $26.4 million derivative loss for our derivative contracts consisting of $16.4 million of realized losses and$10.0 million of unrealized loss from the decrease in the fair value of our open contracts. During the six months ended June 30, 2025, we recorded a $9.3 million derivative gainfor our natural gas derivative contracts consisting of $5.9 million of realized gains and $3.4 million of unrealized gain from the increase in the fair value of our open contracts.
Current report — wording carried from elsewhere
Income tax expense (benefit)* –*Our effective tax rates for the six months ended June 30, 2026 and 2025 were (14.6)% and 12.0%, respectively, and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit and adjustments to the valuation allowance.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
$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.