W&T OFFSHORE INC
For the period ended Sep 30, 2026. Filed Oct 29, 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.
Sep 30, 2026 · Filed Oct 29, 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 2026-06-30; filed 2026-08-05.
0001104659-26-091281
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-09-30; filed 2026-10-29.
0001104659-26-120259
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 82 current paragraphs.
49 unchanged; 28 reworded; 4 added; 5 removed; 2 previous and 1 current paragraphs rearranged.
Tables are not compared: 17 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 (4)
Current report
On October 1, 2026, we entered into the Amended Credit Agreement, pursuant to which our revolving credit facility was converted into a reserve-based revolving credit facility, with an aggregate maximum credit amount of $100.0 million and an aggregate elected commitment amount initially set at $50.0 million**.**For additional information about the Amended Credit Agreement, see Part I, Item 1.Financial Statements – Note 13 – Subsequent Event.
Current report
In its Short-Term Energy Outlook published in October 2026, the Energy Information Administration (the “EIA”) assumes that a combination of convoys through the Strait of Hormuz and workarounds to oil exports from the Middle East, including bypass routes and increased use of ship-to-ship transfers, will lead to production and exports from the region generally increasing through the forecast period. In spite of the increased production and flows from the Middle East, the EIA is forecasting that the spot price for WTI will average $97.00 per barrel in the fourth quarter of 2026 and then fall to an average of $80.00 per barrel in 2027. The attacks on the East-West pipeline in Saudi Arabia highlight the potential for continued volatility in physical oil flows and oil prices amid ongoing withdrawals of oil inventories globally. Additional upward pressure on oil prices stems from extreme tightness in diesel markets that raises demand for oil in order for refiners to meet diesel demand.
Current report
The EIA is forecasting the Henry Hub spot price for natural gas to average $3.16 per MMBtu in 2027, a 9% decrease from 2026. The decrease reflects ongoing higher-than-average natural gas inventories driven by production increases that offset rising liquefied natural gas exports.
Current report
Nine Months Ended September 30, 2026 Compared to the Nine Months Ended September 30, 2025
Removed paragraphs (5)
Previous 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.
Previous 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.
Previous report
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 report
Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025
Previous report
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.
Reworded paragraphs (28)
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 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.
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 September 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 588,500 gross acres (455,800 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, 446,700 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 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.
Current wording
On October 29, 2026, we declared a regular quarterly dividend of $0.01 per share of common stock for the fourth quarter of 2026. We expect to pay the dividend on November 19, 2026 to stockholders of record as of the close of business on November 12, 2026.
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
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 of oil while others are affected by natural gas prices as well as the demand for certain chemical products which are used as feedstock.
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 $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.
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, increased $0.5 million during the three months ended September 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $21.82 per Boe during the three months ended September 30, 2026 compared to $23.27 per Boe during the three months ended September 30, 2025. On a component basis, base LOE decreased $3.2 million, workover expenses increased $1.1 million and facilities maintenance expense increased $2.6 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 decreases 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 expenses 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
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.
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 $3.6 million for the three months ended September 30, 2026 compared to the three months ended September 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 September 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 $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.
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 $0.3 million for the three months ended September 30, 2026 as compared to the three months ended September 30, 2025 primarily due to a decrease of $2.1 million from a lower depletion rate per thousand cubic feet equivalent (“Mcfe”) offset by an increase of $2.0 million from the increase in production. The DD&A rate decreased to $8.04 per Boe for the three months ended September 30, 2026 from $8.73 per Boe for the three months ended September 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and increased 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 $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.
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 $10.2 million for the three months ended September 30, 2026 compared to the three months ended September 30, 2025 primarily due to increases of $6.9 million in share-based compensation costs and $2.9 million in legal and professional fees.
Previous 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.
Current wording
Derivative loss (gain), net* –*During the three months ended September 30, 2026, we recorded a $15.8 million derivative loss for our oil derivative contracts consisting of $9.9 million of realized losses and $5.9 million of unrealized loss from the decrease in the fair value of our open contracts. During the three months ended September 30, 2025, we recorded a $4.1 million derivative gainfor our natural gas derivative contracts consisting of $9.7 million of realized gains offset by $5.6 million of unrealized loss from the decrease in the fair value of our open contracts.
Previous 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.
Current wording
Income tax expense* –*Our effective tax rate for the three months ended September 30, 2026 was (3.8)% and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the valuation allowance. Our effective tax rate for the three months ended September 30, 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of a valuation allowance against our net deferred tax assets.
Previous wording
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 wording
Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between the nine months ended September 30, 2026 and 2025 (in thousands):
Previous wording
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 wording
Production volumes increased by 859 MBoe to 9,930 MBoe during the nine months ended September 30, 2026 compared to the same period in 2025 primarily due to recompletion of a well at our Garden Banks 783 field, restoring production at our West Delta 73 and Eugene Island 64 fields andincreased production from our Mobile Bay fields due to reduced downtime.
Previous wording
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 wording
Lease operating expenses* –*LOE decreased $9.8 million during the nine months ended September 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $21.59 per Boe during the nine months ended September 30, 2026 compared to $24.71 per Boe during the nine months ended September 30, 2025. On a component basis, base LOE decreased $11.0 million, workover expenses decreased $0.6 million and facilities maintenance expense increased $1.8 million.
Previous wording
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 wording
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 nine months ended September 30, 2026.
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 decreases 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 expenses 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.
Previous wording
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 wording
Gathering, transportation and production taxes* –*Gathering, transportation and production taxes increased $7.6 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the nine months ended September 30, 2026.
Previous wording
*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 wording
*Depreciation, depletion and amortization –*DD&A decreased $6.8 million for the nine months ended September 30, 2026 as compared to the nine months ended September 30, 2025 primarilydue to a decrease of $14.5 million from a lower depletion rate per Mcfe offset by an increase of $8.1 million from the increase in production. The DD&A rate decreased to $8.17 per Boe for the nine months ended September 30, 2026 from $9.69 per Boe for the nine months ended September 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and increased proved reserves.
Previous wording
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 wording
General and administrative expenses* –*G&A expenses increased $24.7 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to an increase of $20.4 million in share-based compensation costs and $3.5 million in legal and professional fees.
Previous wording
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 wording
Derivative loss (gain), net* –*During the nine months ended September 30, 2026, we recorded a $42.2 million derivative loss for our oil derivative contracts consisting of $26.2 million of realized losses and$16.0 million of unrealized loss from the decrease in the fair value of our open contracts. During the nine months ended September 30, 2025, we recorded a $13.4 million derivative gainfor our natural gas derivative contracts consisting of $15.5 million of realized gains offset by $2.1 million of unrealized loss from the decrease in the fair value of our open contracts.
Previous wording
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 wording
Other expense, net* –*Other expense, net decreased $9.8 million for the nine months ended September 30, 2026 compared to the same period in 2025 primarily related to an accrual of additional expenses in the nine months ended September 30, 2025 for new 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.
Previous wording
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.
Current wording
Income tax expense* –*Our effective tax rate for the nine months ended September 30, 2026 was (8.1)% and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the valuation allowance. Our effective tax rate for the nine months ended September 30, 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of a valuation allowance against our net deferred tax assets.
Previous 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.
Current wording
We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of September 30, 2026, we had $191.3 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 $68.1 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 $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.
Current wording
Net cash provided by operating activities increased $21.2 million in the nine months ended September 30, 2026 compared to the corresponding period in 2025. This was primarily due to a favorable change of $62.9 million in net loss adjusted for certain noncash items offset by an unfavorable change of $41.7 million in operating cash flows from changes in operating assets and liabilities. The favorable change in net loss adjusted for certain noncash items was primarily related to increases of $100.0 million in revenues offset by an increase of $35.1 million in derivative settlements. The unfavorable change 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 $(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.
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 $(27.1) million and $31.6 million during the nine months ended September 30, 2026 and 2025, respectively. Investments in oil and natural gas properties were $26.9 million and $38.9 million during the nine months ended September 30, 2026 and 2025, respectively. During the nine months ended September 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 $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.
Current wording
Cash flows provided by (used in) financing activities were $5.3 million and $(67.1) million for the nine months ended September 30, 2026 and 2025, respectively. During the nine months ended September 30, 2026, we used $8.0 million in proceeds from our New TVPX Loan to repay the $8.0 million of balloon payment that was due at the maturity date of the TVPX Loan. In addition, we received $14.7 million in net proceeds from the sale of our common stockin connection with our “at-the-market” equity offering program. 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 $5.3 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 $21.7 million in premiums, fees and debt issuance costs.
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 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.
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 nine months ended September 30, 2026, we have paid $26.5 million related to these obligations. Our ARO estimates as of September 30, 2026 and December 31, 2025 were $580.8 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 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.
Current wording
As of September 30, 2026, we have $358.0 million in aggregate principal amount of long-term debt outstanding, with $1.0 million in aggregate principal coming due over the next twelve months.
Previous 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.
Current wording
During the nine months ended September 30, 2026, we declared cash dividends of $4.9 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 (1)
Current report — wording carried from elsewhere
Production volumes increased by 239 Mboe to 3,514 MBoe during the three months ended September 30, 2026 compared to the same period in 2025 primarily due to recompletion of a well at our Garden Banks 783 field.
Rearranged previous paragraphs (2)
Previous report — wording carried 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.
Previous report — wording carried elsewhere
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.