Gulfport Energy Corporation
11/05/2025 | Press release | Distributed by Public on 11/05/2025 11:41
Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the financial statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
The following information updates the discussion of Gulfport's financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2024 ("2024 Form 10-K") and analyzes the changes in the results of operations between the periods of July 1, 2025 through September 30, 2025, January 1, 2025 through September 30, 2025, July 1, 2024 through September 30, 2024 and January 1, 2024 through September 30, 2024. For definitions of commonly used natural gas and oil terms found in this Quarterly Report on Form 10-Q, please refer to the "Definitions" provided in this report.
Overview
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.
Recent Developments
Credit Facility
On October 30, 2025, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $1.0 billion.
Share Repurchase Program and Redemption of Preferred Stock
On August 4, 2025, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $1.0 billion to $1.5 billion (including the redemption of preferred stock noted below) and extended the authorization through December 31, 2026.
On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. During the period between the date of notice of the redemption and the Redemption Date, 28,907 shares of preferred stock were converted into approximately 2.1 million shares of common stock. On the Redemption Date, the Company redeemed the remaining 2,449 shares of preferred stock for cash totaling $31.3 million. Additionally, direct transaction-related costs of $1.1 million were incurred as part of the redemption.
During the three months ended September 30, 2025, the Company repurchased 438,266 shares for $76.3 million at a weighted average price of $174.01 per share. As of September 30, 2025, the Company repurchased 6.7 million shares for $785.4 million at a weighted average price of $117.45 per share since the inception of the Repurchase Program.
Tariffs and Trading Relationships
Since the initial U.S. government announcement regarding tariffs in April 2025, the U.S. government has implemented and subsequently announced and modified, delayed or rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Certain foreign jurisdictions have likewise threatened, and in some cases implemented, tariffs on U.S. goods. In August 2025, the U.S. Court of Appeals for the Federal Circuit determined that several tariffs imposed under the administration exceed presidential authority and therefore are invalid, though the decision has been stayed pending U.S. Supreme Court review. Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of raw materials, contribute to inflation in the markets in which we operate, delay access to capital markets and increase the likelihood of an economic downturn. Although we are continuing to monitor the economic effects of such announcements and developments, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs and retaliatory tariffs remain uncertain.
One Big Beautiful Bill Act
On July 4, 2025, the President signed into law the legislation commonly referred to as the One Big Beautiful Bill Act ("OBBBA"), which introduces significant changes to U.S. federal tax law. Key provisions of the OBBBA that are relevant to the Company include modifications to the limitations on the deductibility of interest expense under Section 163(j) of the Internal Revenue Code and adjustments to bonus depreciation rules.
2025 Operational and Financial Highlights
During the third quarter of 2025, we had the following notable achievements:
•Reported total net production of 1,119.7 MMcfe per day.
•Turned to sales seven gross (7.0 net) operated wells.
•Generated $209.1 million of operating cash flows.
•Executed optional redemption of outstanding preferred stock, simplifying our capital structure and eliminating future dividend obligations on the preferred stock.
•Repurchased 438,266 shares of common stock (including the underlying shares of common stock into which the preferred stock was convertible) for $76.3 million at a weighted average price of $174.01 per share.
•Exited the quarter with total liquidity of $903.7 million.
2025 Production and Drilling Activity
Production Volumes
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | ||||||||||
| Natural gas (Mcf/day) | |||||||||||
| Utica & Marcellus | 833,710 | 822,015 | |||||||||
| SCOOP | 154,035 | 144,507 | |||||||||
| Total | 987,746 | 966,522 | |||||||||
| Oil and condensate (Bbl/day) | |||||||||||
| Utica & Marcellus | 5,485 | 3,105 | |||||||||
| SCOOP | 1,408 | 1,513 | |||||||||
| Total | 6,892 | 4,618 | |||||||||
| NGL (Bbl/day) | |||||||||||
| Utica & Marcellus | 8,364 | 3,491 | |||||||||
| SCOOP | 6,733 | 6,998 | |||||||||
| Total | 15,097 | 10,489 | |||||||||
| Combined (Mcfe/day) | |||||||||||
| Utica & Marcellus | 916,801 | 861,592 | |||||||||
| SCOOP | 202,877 | 195,572 | |||||||||
| Total | 1,119,678 | 1,057,164 | |||||||||
| Totals may not sum or recalculate due to rounding. | |||||||||||
Our total net production averaged approximately 1,119.7 MMcfe per day during the three months ended September 30, 2025, as compared to 1,057.2 MMcfe per day during the three months ended September 30, 2024. Production per day increased primarily due to the timing of our 2024 and 2025 development programs.
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||
| Natural gas (Mcf/day) | |||||||||||
| Utica & Marcellus | 752,902 | 816,788 | |||||||||
| SCOOP | 153,287 | 154,054 | |||||||||
| Total | 906,189 | 970,842 | |||||||||
| Oil and condensate (Bbl/day) | |||||||||||
| Utica & Marcellus | 5,166 | 1,815 | |||||||||
| SCOOP | 1,512 | 1,754 | |||||||||
| Total | 6,678 | 3,569 | |||||||||
| NGL (Bbl/day) | |||||||||||
| Utica & Marcellus | 5,489 | 2,610 | |||||||||
| SCOOP | 6,654 | 7,629 | |||||||||
| Total | 12,143 | 10,239 | |||||||||
| Combined (Mcfe/day) | |||||||||||
| Utica & Marcellus | 816,835 | 843,339 | |||||||||
| SCOOP | 202,282 | 210,348 | |||||||||
| Total | 1,019,116 | 1,053,687 | |||||||||
| Totals may not sum or recalculate due to rounding. | |||||||||||
Our total net production averaged approximately 1,019.1 MMcfe per day during the nine months ended September 30, 2025, as compared to 1,053.7 MMcfe per day during the nine months ended September 30, 2024. Production per day declined primarily due to natural declines and the impact of unplanned, third-party midstream outages and constraints, partially offset by our 2024 and 2025 development programs.
Utica/Marcellus. We spud nine gross (9.0 net) wells targeting the Utica formation during the three months ended September 30, 2025. In addition, we commenced sales on seven gross (7.0 net) operated Utica wells.
SCOOP. We did not spud or commence sales on any operated wells in the SCOOP during the three months ended September 30, 2025.
RESULTS OF OPERATIONS
Comparison of the Three Month Periods Ended September 30, 2025 and 2024
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)
The following table summarizes our natural gas, oil and condensate and NGL production and related pricing for the three months ended September 30, 2025 as compared to the three months ended September 30, 2024. Some totals below may not sum or recalculate due to rounding.
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | ||||||||||
| Natural gas sales | |||||||||||
| Natural gas production volumes (MMcf) | 90,873 | 88,920 | |||||||||
| Natural gas production volumes (MMcf) per day | 988 | 967 | |||||||||
| Total sales | $ | 236,801 | $ | 159,862 | |||||||
| Average price without the impact of derivatives ($/Mcf) | $ | 2.61 | $ | 1.80 | |||||||
| Impact from settled derivatives ($/Mcf) | $ | 0.34 | $ | 0.95 | |||||||
| Average price, including settled derivatives ($/Mcf) | $ | 2.95 | $ | 2.75 | |||||||
| Oil and condensate sales | |||||||||||
| Oil and condensate production volumes (MBbl) | 634 | 425 | |||||||||
| Oil and condensate production volumes (MBbl) per day | 7 | 5 | |||||||||
| Total sales | $ | 37,406 | $ | 29,467 | |||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 58.99 | $ | 69.35 | |||||||
| Impact from settled derivatives ($/Bbl) | $ | 3.63 | $ | 0.22 | |||||||
| Average price, including settled derivatives ($/Bbl) | $ | 62.62 | $ | 69.57 | |||||||
| NGL sales | |||||||||||
| NGL production volumes (MBbl) | 1,389 | 965 | |||||||||
| NGL production volumes (MBbl) per day | 15 | 10 | |||||||||
| Total sales | $ | 38,734 | $ | 26,617 | |||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 27.89 | $ | 27.58 | |||||||
| Impact from settled derivatives ($/Bbl) | $ | 0.21 | $ | (0.16) | |||||||
| Average price, including settled derivatives ($/Bbl) | $ | 28.10 | $ | 27.42 | |||||||
| Natural gas, oil and condensate and NGL sales | |||||||||||
| Natural gas equivalents (MMcfe) | 103,010 | 97,259 | |||||||||
| Natural gas equivalents (MMcfe) per day | 1,120 | 1,057 | |||||||||
| Total sales | $ | 312,941 | $ | 215,946 | |||||||
| Average price without the impact of derivatives ($/Mcfe) | $ | 3.04 | $ | 2.22 | |||||||
| Impact from settled derivatives ($/Mcfe) | $ | 0.33 | $ | 0.87 | |||||||
| Average price, including settled derivatives ($/Mcfe) | $ | 3.37 | $ | 3.09 | |||||||
| Production Costs: | |||||||||||
| Average lease operating expenses ($/Mcfe) | $ | 0.20 | $ | 0.19 | |||||||
| Average taxes other than income ($/Mcfe) | $ | 0.08 | $ | 0.07 | |||||||
| Average transportation, gathering, processing and compression ($/Mcfe) | $ | 0.94 | $ | 0.92 | |||||||
| Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe) | $ | 1.21 | $ | 1.18 | |||||||
Natural Gas, Oil and Condensate and NGL Sales (in thousands)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | % Change | |||||||||||||||
| Natural gas | $ | 236,801 | $ | 159,862 | 48 | % | |||||||||||
| Oil and condensate | 37,406 | 29,467 | 27 | % | |||||||||||||
| NGL | 38,734 | 26,617 | 46 | % | |||||||||||||
| Natural gas, oil and condensate and NGL sales | $ | 312,941 | $ | 215,946 | 45 | % | |||||||||||
The increase in natural gas sales without the impact of derivatives, when comparing the three months ended September 30, 2025 to the three months ended September 30, 2024 was due to a 45% increase in realized prices and a 2% increase in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $2.16 per Mcf in the three months ended September 30, 2024, to $3.07 per Mcf during the three months ended September 30, 2025. The 2% increase in natural gas production was primarily due to commencement of sales on new wells.
The increase in oil and condensate sales without the impact of derivatives, when comparing the three months ended September 30, 2025 to the three months ended September 30, 2024, was due to a 49% increase in sales volumes, partially offset by a 15% decrease in realized prices. The 49% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids windows. The realized price change was primarily driven by the decrease in the average WTI crude index from $75.09 per barrel in the three months ended September 30, 2024, to $64.93 per barrel during the three months ended September 30, 2025.
The increase in NGL sales without the impact of derivatives, when comparing the three months ended September 30, 2025 to the three months ended September 30, 2024, was due to a 44% increase in sales volumes and a 1% increase in realized prices. The 44% increase in NGL production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids windows.
Natural Gas, Oil and NGL Derivatives (in thousands)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | ||||||||||
| Natural gas derivatives - fair value gains (losses) | $ | 33,868 | $ | (57,168) | |||||||
| Natural gas derivatives - settlement gains | 31,150 | 84,943 | |||||||||
| Total gains on natural gas derivatives | 65,018 | 27,775 | |||||||||
| Oil derivatives - fair value (losses) gains | (2,674) | 6,698 | |||||||||
| Oil derivatives - settlement gains | 2,302 | 93 | |||||||||
| Total (losses) gains on oil and condensate derivatives | (372) | 6,791 | |||||||||
| NGL derivatives - fair value gains | 1,858 | 3,559 | |||||||||
| NGL derivatives - settlement gains (losses) | 300 | (159) | |||||||||
| Total gains on NGL derivatives | 2,158 | 3,400 | |||||||||
| Total gains on natural gas, oil and NGL derivatives | $ | 66,804 | $ | 37,966 | |||||||
We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant change in the total gain for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. See Note 10of our consolidated financial statements for hedged volumes and pricing.
Lease Operating Expenses (in thousands, except per unit)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | % Change | |||||||||||||||
| Lease operating expenses | |||||||||||||||||
| Utica & Marcellus | $ | 15,558 | $ | 13,080 | 19 | % | |||||||||||
| SCOOP | 5,235 | 5,138 | 2 | % | |||||||||||||
| Total lease operating expenses | $ | 20,793 | $ | 18,218 | 14 | % | |||||||||||
| Lease operating expenses per Mcfe | |||||||||||||||||
| Utica & Marcellus | $ | 0.18 | $ | 0.17 | 6 | % | |||||||||||
| SCOOP | 0.28 | 0.29 | (3) | % | |||||||||||||
| Total lease operating expenses per Mcfe | $ | 0.20 | $ | 0.19 | 8 | % | |||||||||||
The increase in our total and per unit LOE for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, was primarily the result of an increase in workover, compression and labor expenses in our Utica operations.
Taxes Other Than Income (in thousands, except per unit)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | % Change | |||||||||||||||
| Production taxes | $ | 5,300 | $ | 4,528 | 17 | % | |||||||||||
| Property taxes | 1,921 | 1,797 | 7 | % | |||||||||||||
| Other | 704 | 508 | 39 | % | |||||||||||||
| Total taxes other than income | $ | 7,925 | $ | 6,833 | 16 | % | |||||||||||
| Total taxes other than income per Mcfe | $ | 0.08 | $ | 0.07 | 10 | % | |||||||||||
The increase in total and per unit taxes other than income for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, was primarily related to an increase in production taxes resulting from the increase in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.
Transportation, Gathering, Processing and Compression (in thousands, except per unit)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | % Change | |||||||||||||||
| Transportation, gathering, processing and compression | $ | 96,390 | $ | 89,900 | 7 | % | |||||||||||
| Transportation, gathering, processing and compression per Mcfe | $ | 0.94 | $ | 0.92 | 1 | % | |||||||||||
Transportation, gathering, processing and compression for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, increased on a total and per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate sales.
Depreciation, Depletion and Amortization (in thousands, except per unit)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | % Change | |||||||||||||||
| Depreciation, depletion and amortization of oil and gas properties | $ | 82,680 | $ | 82,368 | - | % | |||||||||||
| Depreciation, depletion and amortization of other property and equipment | 536 | 457 | 17 | % | |||||||||||||
| Total depreciation, depletion and amortization | $ | 83,216 | $ | 82,825 | - | % | |||||||||||
| Depreciation, depletion and amortization per Mcfe | $ | 0.81 | $ | 0.85 | (5) | % | |||||||||||
Depreciation, depletion and amortization of our oil and gas properties for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, increased primarily due to the 6% increase in our production partially offset by a lower depletion rate resulting from a decline in our amortization base from the full cost ceiling test impairments incurred during 2024.
Impairment of Oil and Natural Gas Properties
At September 30, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million for the three months ended September 30, 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. We did not record an impairment during the three months ended September 30, 2025.
General and Administrative Expenses (in thousands, except per unit)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | % Change | |||||||||||||||
| General and administrative expenses, gross | $ | 22,113 | $ | 20,694 | 7 | % | |||||||||||
| Reimbursed from third parties | (4,040) | (3,720) | 9 | % | |||||||||||||
| Capitalized general and administrative expenses | (6,238) | (6,495) | (4) | % | |||||||||||||
| General and administrative expenses, net | $ | 11,835 | $ | 10,479 | 13 | % | |||||||||||
| General and administrative expenses, net per Mcfe | $ | 0.11 | $ | 0.11 | 7 | % | |||||||||||
The increase in general and administrative expenses for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, was primarily driven by an increase in legal expense related to the matters disclosed in Note 9of our consolidated financial statements.
Interest Expense (in thousands, except per unit)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | % Change | |||||||||||||||
| Interest on 2026 Senior Notes | $ | - | $ | 9,014 | (100) | % | |||||||||||
| Interest on 2029 Senior Notes | 10,969 | 2,194 | 400 | % | |||||||||||||
| Interest expense on Credit Facility | 2,557 | 4,423 | (42) | % | |||||||||||||
| Amortization of loan costs | 1,316 | 1,016 | 30 | % | |||||||||||||
| Capitalized interest | (1,536) | (1,230) | 25 | % | |||||||||||||
| Other | 284 | 449 | (37) | % | |||||||||||||
| Total interest expense | $ | 13,590 | $ | 15,866 | (14) | % | |||||||||||
| Interest expense per Mcfe | $ | 0.13 | $ | 0.16 | (19) | % | |||||||||||
Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 and the redemption of the remaining balance of the 2026 Senior Notes in the second quarter of 2025, interest paid on the 2026 Senior Notes decreased 100% for the three months ended September 30, 2025 compared to the three months ended September 30, 2024. The Company also incurred $11.0 million of interest on the 2029 Senior Notes for the three months ended September 30, 2025 compared to $2.2 million for the three months ended September 30, 2024 due to the 2029 Senior Notes being issued in September 2024. Interest expense on our Credit Facility decreased 42% for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, as a result of a lower average interest rate and outstanding balance. Amortization of loan costs increased 30% for the three months ended September 30, 2025 compared to the three months ended September 30, 2024, as a result of the Fourth Amendment to the Credit Facility and the issuance of the 2029 Senior Notes. See Note 4of our consolidated financial statements for further details of our Credit Facility and 2029 Senior Notes. The Company also capitalized $1.5 million and $1.2 million in interest expense for the three months ended September 30, 2025 and September 30, 2024, respectively.
Loss on Debt Extinguishment
In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were purchased at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million.
Income Taxes
We recorded income tax expense of $31.4 million and income tax benefit of $3.8 million for the three months ended September 30, 2025 and September 30, 2024, respectively. On July 4, 2025, the OBBBA, which includes a broad range of tax reform provisions, was signed into law in the United States. The Company has completed its initial assessment of the OBBBA's provisions which are expected to affect the Company's current tax expense and deferred tax assets and liabilities. The Company has incorporated the provisions into the financial statements for the current period and is continuing to evaluate the full implications of these legislative changes. See Note 14of our consolidated financial statements for further discussion of our income tax expense.
Comparison of the Nine Month Periods Ended September 30, 2025 and 2024
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)
The following table summarizes our natural gas, oil and condensate, and NGL production and related pricing for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024. Some totals below may not sum or recalculate due to rounding.
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||
| Natural gas sales | |||||||||||
| Natural gas production volumes (MMcf) | 247,390 | 266,011 | |||||||||
| Natural gas production volumes (MMcf) per day | 906 | 971 | |||||||||
| Total sales | $ | 759,543 | $ | 492,606 | |||||||
| Average price without the impact of derivatives ($/Mcf) | $ | 3.07 | $ | 1.85 | |||||||
| Impact from settled derivatives ($/Mcf) | $ | 0.16 | $ | 0.91 | |||||||
| Average price, including settled derivatives ($/Mcf) | $ | 3.23 | $ | 2.76 | |||||||
| Oil and condensate sales | |||||||||||
| Oil and condensate production volumes (MBbl) | 1,823 | 978 | |||||||||
| Oil and condensate production volumes (MBbl) per day | 7 | 4 | |||||||||
| Total sales | $ | 110,208 | $ | 70,295 | |||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 60.45 | $ | 71.89 | |||||||
| Impact from settled derivatives ($/Bbl) | $ | 2.86 | $ | (0.17) | |||||||
| Average price, including settled derivatives ($/Bbl) | $ | 63.31 | $ | 71.72 | |||||||
| NGL sales | |||||||||||
| NGL production volumes (MBbl) | 3,315 | 2,805 | |||||||||
| NGL production volumes (MBbl) per day | 12 | 10 | |||||||||
| Total sales | $ | 98,287 | $ | 80,870 | |||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 29.65 | $ | 28.83 | |||||||
| Impact from settled derivatives ($/Bbl) | $ | (0.40) | $ | (0.55) | |||||||
| Average price, including settled derivatives ($/Bbl) | $ | 29.25 | $ | 28.28 | |||||||
| Natural gas, oil and condensate and NGL sales | |||||||||||
| Natural gas equivalents (MMcfe) | 278,219 | 288,710 | |||||||||
| Natural gas equivalents (MMcfe) per day | 1,019 | 1,054 | |||||||||
| Total sales | $ | 968,038 | $ | 643,771 | |||||||
| Average price without the impact of derivatives ($/Mcfe) | $ | 3.48 | $ | 2.23 | |||||||
| Impact from settled derivatives ($/Mcfe) | $ | 0.16 | $ | 0.83 | |||||||
| Average price, including settled derivatives ($/Mcfe) | $ | 3.64 | $ | 3.06 | |||||||
| Production Costs: | |||||||||||
| Average lease operating expenses ($/Mcfe) | $ | 0.21 | $ | 0.18 | |||||||
| Average taxes other than income ($/Mcfe) | $ | 0.08 | $ | 0.08 | |||||||
| Average transportation, gathering, processing and compression ($/Mcfe) | $ | 0.96 | $ | 0.91 | |||||||
| Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe) | $ | 1.25 | $ | 1.16 | |||||||
Natural Gas, Oil and Condensate and NGL Sales (in thousands)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | % Change | |||||||||||||||
| Natural gas | $ | 759,543 | $ | 492,606 | 54 | % | |||||||||||
| Oil and condensate | 110,208 | 70,295 | 57 | % | |||||||||||||
| NGL | 98,287 | 80,870 | 22 | % | |||||||||||||
| Natural gas, oil and condensate and NGL sales | $ | 968,038 | $ | 643,771 | 50 | % | |||||||||||
The increase in natural gas sales without the impact of derivatives, when comparing the nine months ended September 30, 2025 to the nine months ended September 30, 2024, was due to a 66% increase in realized prices, partially offset by a 7% decrease in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $2.10 per Mcf in the nine months ended September 30, 2024, to $3.39 per Mcf in the nine months ended September 30, 2025. The 7% decrease in natural gas production was primarily due to natural declines partially offset by our 2024 and 2025 development programs and the impact of unplanned, third-party midstream outages and constraints.
The increase in oil and condensate sales without the impact of derivatives, when comparing the nine months ended September 30, 2025 to the nine months ended September 30, 2024, was due to a 86% increase in sales volumes, partially offset by a 16% decrease in realized prices. The 86% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids windows. The realized price change was driven by the decrease in the average WTI crude index from $77.54 per barrel in the nine months ended September 30, 2024, to $66.70 per barrel in the nine months ended September 30, 2025.
The increase in NGL sales without the impact of derivatives, when comparing the nine months ended September 30, 2025 to the nine months ended September 30, 2024, was due to a 18% increase in sales volumes and a 3% increase in realized prices. The 18% increase in NGL production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids windows.
Natural Gas, Oil and NGL Derivatives (in thousands)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||
| Natural gas derivatives - fair value gains (losses) | $ | 9,113 | $ | (168,516) | |||||||
| Natural gas derivatives - settlement gains | 39,420 | 242,645 | |||||||||
| Total gains on natural gas derivatives | 48,533 | 74,129 | |||||||||
| Oil derivatives - fair value (losses) gains | (365) | 4,832 | |||||||||
| Oil derivatives - settlement gains (losses) | 5,217 | (166) | |||||||||
| Total gains on oil and condensate derivatives | 4,852 | 4,666 | |||||||||
| NGL derivatives - fair value gains (losses) | 4,307 | (2,771) | |||||||||
| NGL derivatives - settlement losses | (1,335) | (1,537) | |||||||||
| Total gains (losses) on NGL derivatives | 2,972 | (4,308) | |||||||||
| Total gains on natural gas, oil and NGL derivatives | $ | 56,357 | $ | 74,487 | |||||||
We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant change in the total gain for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. See Note 10of our consolidated financial statements for hedged volumes and pricing.
Lease Operating Expenses (in thousands, except per unit)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | % Change | |||||||||||||||
| Lease operating expenses | |||||||||||||||||
| Utica & Marcellus | $ | 41,572 | $ | 34,560 | 20 | % | |||||||||||
| SCOOP | 17,132 | 16,283 | 5 | % | |||||||||||||
| Total lease operating expenses | $ | 58,704 | $ | 50,843 | 15 | % | |||||||||||
| Lease operating expenses per Mcfe | |||||||||||||||||
| Utica & Marcellus | $ | 0.19 | $ | 0.15 | 27 | % | |||||||||||
| SCOOP | 0.31 | 0.28 | 11 | % | |||||||||||||
| Total lease operating expenses per Mcfe | $ | 0.21 | $ | 0.18 | 20 | % | |||||||||||
The increase in our total and per unit LOE for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, was primarily the result of an increase in water hauling, repairs and maintenance and labor expenses in our Utica operations.
Taxes Other Than Income (in thousands, except per unit)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | % Change | |||||||||||||||
| Production taxes | $ | 16,054 | $ | 14,236 | 13 | % | |||||||||||
| Property taxes | 3,902 | 6,326 | (38) | % | |||||||||||||
| Other | 2,151 | 1,549 | 39 | % | |||||||||||||
| Total taxes other than income | $ | 22,107 | $ | 22,111 | - | % | |||||||||||
| Total taxes other than income per Mcfe | $ | 0.08 | $ | 0.08 | 4 | % | |||||||||||
The total and per unit taxes other than income for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, remained consistent.
Transportation, Gathering, Processing and Compression (in thousands, except per unit)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | % Change | |||||||||||||||
| Transportation, gathering, processing and compression | $ | 265,768 | $ | 263,048 | 1 | % | |||||||||||
| Transportation, gathering, processing and compression per Mcfe | $ | 0.96 | $ | 0.91 | 5 | % | |||||||||||
Transportation, gathering, processing and compression for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 increased on a total and per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate sales.
Depreciation, Depletion and Amortization (in thousands, except per unit)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | % Change | |||||||||||||||
| Depreciation, depletion and amortization of oil and gas properties | $ | 220,893 | $ | 240,279 | (8) | % | |||||||||||
| Depreciation, depletion and amortization of other property and equipment | 1,588 | 1,122 | 42 | % | |||||||||||||
| Total depreciation, depletion and amortization | $ | 222,481 | $ | 241,401 | (8) | % | |||||||||||
| Depreciation, depletion and amortization per Mcfe | $ | 0.80 | $ | 0.84 | (4) | % | |||||||||||
The total and per unit depreciation, depletion and amortization of our oil and gas properties for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, decreased primarily due to a lower depletion rate resulting from a decline in our amortization base from the full cost ceiling test impairments recorded during 2024, combined with a decrease in our production as noted above.
Impairment of Oil and Natural Gas Properties
At September 30, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million for the nine months ended September 30, 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. We did not record an impairment in the first or second quarters of 2024 or during the nine months ended September 30, 2025.
General and Administrative Expenses (in thousands, except per unit)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | % Change | |||||||||||||||
| General and administrative expenses, gross | $ | 62,953 | $ | 59,921 | 5 | % | |||||||||||
| Reimbursed from third parties | (12,287) | (10,962) | 12 | % | |||||||||||||
| Capitalized general and administrative expenses | (18,904) | (18,530) | 2 | % | |||||||||||||
| General and administrative expenses, net | $ | 31,762 | $ | 30,429 | 4 | % | |||||||||||
| General and administrative expenses, net per Mcfe | $ | 0.11 | $ | 0.11 | 8 | % | |||||||||||
The increase in general and administrative expenses for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, was primarily driven by increases in employee compensation and legal expense related to the matters disclosed in Note 9of our consolidated financial statements.
Interest Expense (in thousands, except per unit)
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | % Change | |||||||||||||||
| Interest on 2026 Senior Notes | $ | 777 | $ | 31,014 | (97) | % | |||||||||||
| Interest on 2029 Senior Notes | 32,906 | 2,194 | 1400 | % | |||||||||||||
| Interest expense on Credit Facility | 6,564 | 12,001 | (45) | % | |||||||||||||
| Amortization of loan costs | 3,929 | 2,910 | 35 | % | |||||||||||||
| Capitalized interest | (4,412) | (3,603) | 22 | % | |||||||||||||
| Other | 913 | 1,511 | (40) | % | |||||||||||||
| Total interest expense | $ | 40,677 | $ | 46,027 | (12) | % | |||||||||||
| Interest expense per Mcfe | $ | 0.15 | $ | 0.16 | (8) | % | |||||||||||
Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 and the redemption of the remaining balance in the second quarter of 2025, interest paid on the 2026 Senior Notes decreased 97% for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024. The Company also incurred $32.9 million of interest on the 2029 Senior Notes for the nine months ended September 30, 2025. Interest expense on our Credit Facility decreased 45% for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, as a result of a lower average interest rate and outstanding balance. Amortization of loan costs increased 35% for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, as a result of the Fourth Amendment to the Credit Facility and the issuance of the 2029 Senior Notes. See Note 4of our consolidated financial statements for further details of our Credit Facility and 2029 Senior Notes. The Company also capitalized $4.4 million and $3.6 million in interest expense for the nine months ended September 30, 2025 and September 30, 2024, respectively.
Loss on Debt Extinguishment
In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were purchased at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million.
Income Taxes
We recorded income tax expense of $82.9 million and $3.4 million for the nine months ended September 30, 2025 and September 30, 2024, respectively. On July 4, 2025, the OBBBA, which includes a broad range of tax reform provisions, was signed into law in the United States. The Company has completed its initial assessment of the OBBBA's provisions which are expected to affect the Company's current tax expense and deferred tax assets and liabilities. The Company has incorporated the provisions into the financial statements for the current period and is continuing to evaluate the full implications of these legislative changes. See Note 14of our consolidated financial statements for further discussion of our income tax expense.
Liquidity and Capital Resources
Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. We generally fund our operations, planned capital expenditures and any share repurchases or redemptions with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility. Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
For the three and nine months ended September 30, 2025, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases and dividend payments on our preferred stock.
We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.
To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 4of our consolidated financial statements for further discussion of our debt obligations, including the principal and carrying amounts of our senior notes.
As of September 30, 2025, we had $3.4 million of cash and cash equivalents, $51.0 million of outstanding borrowings under our Credit Facility, $48.7 million of letters of credit outstanding, and $650.0 million of outstanding 2029 Senior Notes. Our total principal amount of funded debt as of September 30, 2025 was $701.0 million.
As of October 29, 2025 we had $3.3 million of cash and cash equivalents, $33.0 million in borrowings under our Credit Facility, $48.7 million of letters of credit outstanding, and $650 million of outstanding 2029 Senior Notes.
Debt. In May 2021, we issued our 2026 Senior Notes. The 2026 Senior Notes were guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility. In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million, of the 2026 Senior Notes in a tender offer using net proceeds received from the private placement of the 2029 Senior Notes. In May 2025, the Company redeemed the remaining balance of its 2026 Senior Notes at par for $25.7 million. No additional fees or penalties were incurred as a result of the early redemption.
Additionally, on May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the "Third Amendment") which amended the Company's Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $900 million, (b) increased the borrowing base under the Credit Facility to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day. On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.
On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the "Fourth Amendment"), which amended the Company's Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid by 50 bps. On May 5, 2025, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $1.0 billion.
See Note 4of our consolidated financial statements for additional discussion of our outstanding debt.
Dividends on Preferred Stock. As discussed in Note 5of our consolidated financial statements, holders of preferred stock were entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock ("PIK Dividends"). We had the option to pay either cash dividends or PIK Dividends on a quarterly basis. On September 5, 2025, the Company redeemed all of its outstanding preferred stock. As a result, the Company did 0 pay cash dividends to holders of our preferred stock during the three months ended September 30, 2025. The Company paid $1.7 million of cash dividends to holders of our preferred stock during the nine months ended September 30, 2025, and $1.1 million and $3.3 million during the three and nine months ended September 30, 2024, respectively.
Supplemental Guarantor Financial Information. The 2026 Senior Notes were guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the "2026 Senior Notes Guarantors"). The 2026 Senior Notes were not guaranteed by Grizzly Holdings or Mule Sky, LLC. The 2026 Senior Notes Guarantors were 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There were no significant restrictions on the ability of the Parent or the 2026 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 2026 Senior Notes and the guarantees were effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.
The 2029 Senior Notes are guaranteed on a senior unsecured basis by Gulfport and certain of Gulfport's wholly owned subsidiaries (collectively, the "2029 Senior Notes Guarantors" and, together with the 2026 Senior Notes Guarantors, the "Guarantors") and certain future subsidiaries of Gulfport that become borrowers or guarantors under any credit agreement with an aggregate principal amount outstanding or commitment amount in excess of $15 million. The 2029 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2029 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating's subsidiaries that are not 2029 Senior Notes Guarantors.
SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 3Quantitative and Qualitative Disclosures About Market Risk for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 10 of our consolidated financial statements for further discussion of derivatives and hedging activities.
Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the nine months ended September 30, 2025, the Company's incurred capital expenditures totaled $387.0 million related to operated activities, of which $347.8 million related to drilling and completion activities, $23.4 million related to maintenance leasehold and land investment and $15.7 million related to discretionary acreage acquisitions.
Our operated base drilling and completion capital expenditures for 2025 are currently estimated to be approximately $355.0 million. Also, we currently expect to spend approximately $35.0 million in 2025 for maintenance leasehold and land investment, which is focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2025, 2026 and 2027. Our capital program is expected to deliver approximately 1,040 MMcfe per day of production in 2025 and was impacted by unplanned, third-party midstream outages and constraints throughout the year.
The Company has also elected to invest an incremental $30.0 million toward discretionary appraisal projects during 2025, which includes capital expenditures allocated toward drilled but uncompleted and recompletion activity and the Company's first U-development in the Utica. The Company also plans to invest an incremental $35.0 million toward discretionary development activity that is anticipated to mitigate upcoming production downtime due to offset operator simultaneous operations and planned midstream maintenance downtime in early 2026.
Additionally, we are pursuing accretive acreage opportunities that expand our resource footprint and provide optionality to our near-term development plans and intend to allocate approximately $75.0 million to $100.0 million in discretionary acreage acquisitions for 2025 and early 2026.
Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the nine months ended September 30, 2025 and 2024 (in thousands):
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||
| Net cash provided by operating activities | $ | 617,761 | $ | 501,185 | |||||||
| Additions to oil and natural gas properties | (382,899) | (376,910) | |||||||||
| Debt activity, net | (12,702) | 24,761 | |||||||||
| Debt issuance and loan commitment fees | - | (14,820) | |||||||||
| Repurchases of common stock | (168,023) | (103,885) | |||||||||
| Redemption of preferred stock | (31,374) | - | |||||||||
| Net cash payments on performance vesting restricted stock units | (12,297) | - | |||||||||
| Shares exchanged for tax withholdings | (5,576) | (23,606) | |||||||||
| Dividends on preferred stock | (1,666) | (3,293) | |||||||||
| Other | (1,330) | (2,141) | |||||||||
| Net change in cash and cash equivalents | $ | 1,894 | $ | 1,291 | |||||||
| Cash and cash equivalents at end of period | $ | 3,367 | $ | 3,220 | |||||||
Net cash provided by operating activities. Net cash flow provided by operating activities was $617.8 million for the nine months ended September 30, 2025, as compared to $501.2 million for the nine months ended September 30, 2024. The increase was primarily the result of increases in natural gas revenues.
Additions to oil and natural gas properties. During the nine months ended September 30, 2025, we spud 21 gross (20.9 net) operated wells and commenced sales from 26 gross (26.0 net) operated wells in the Utica and Marcellus for a total incurred cost of approximately $320.8 million. During the nine months ended September 30, 2025, we completed drilling and commenced sales from two gross (1.8 net) operated wells in the SCOOP for a total incurred cost of approximately $27.0 million.
Drilling and completion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the nine months ended September 30, 2025 and 2024, were as follows (in thousands):
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||
| Oil and Natural Gas Property Cash Expenditures: | |||||||||||
| Drilling and completion costs | $ | 323,737 | $ | 267,802 | |||||||
| Leasehold acquisitions | 38,246 | 89,931 | |||||||||
| Other | 20,916 | 19,177 | |||||||||
| Total oil and natural gas property expenditures | $ | 382,899 | $ | 376,910 | |||||||
Debt activity, net. In the nine months ended September 30, 2025, the Company had $1.0 billion and $994.0 million in borrowings and repayments, respectively, on its Credit Facility. In September 2024, the Company purchased $524.3 million of the 2026 Senior Notes in a tender offer. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million. The Company also issued $650.0 million aggregate principal amount of its 6.750% senior notes due 2029. In May 2025, the Company redeemed the remaining balance of its 2026 Senior Notes at par for $25.7 million. No additional fees or penalties were incurred as a result of the early redemption. The final payment, including accrued interest, totaled $26.6 million. As of October 29, 2025 the Company had $33.0 million in borrowings outstanding on its Credit Facility.
Debt issuance and loan commitment fees. During the nine months ended September 30, 2024, the Company incurred debt issuance and loan commitment fees of $14.8 million related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4of our consolidated financial statements for further discussion of the long-term debt activity.
Repurchases of common stock. During the nine months ended September 30, 2025, the Company repurchased 1.1 million shares for approximately $201.3 million under the Repurchase Program at a weighted average price of $180.05 per share. For the same period in 2024, the Company repurchased 0.7 million shares for $104.4 million at a weighted average price of $146.60 per share. As of October 29, 2025, we repurchased 6.8 million shares for approximately $814.4 million under the Repurchase Program at a weighted average price of $118.98 per share.
Redemption of preferred stock. On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. During the period between the date of the notice of redemption and the Redemption Date, 28,907 shares of preferred stock were converted into approximately 2.1 million shares of common stock. On the Redemption Date, the Company redeemed the remaining 2,449 shares of preferred stock for cash totaling $31.3 million. Additionally, direct transaction-related costs of $1.1 million were incurred as part of the redemption. See Note 5of our consolidated financial statements for further discussion of the redemption of preferred stock.
Net cash payments on performance vesting restricted stock units. During the nine months ended September 30, 2025, the Company settled certain performance vesting restricted stock units awards that were granted in 2022 in cash for $12.3 million, as discussed in Note 7of our consolidated financial statements.
Dividends on preferred stock. During the nine months ended September 30, 2025, the Company paid $1.7 million of cash dividends to holders of our preferred stock compared to $3.3 million in the nine months ended September 30, 2024.
Shares exchanged for tax withholdings. During the nine months ended September 30, 2025, the Company paid $5.6 million of shares exchanged for tax withholdings compared to $23.6 million in the nine months ended September 30, 2024. The decrease was primarily due to lower aggregate fair value of vested awards during the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, as discussed in Note 7of our consolidated financial statements.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities, as discussed in Note 9of our consolidated financial statements. There have been no other material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024.
Off-balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2025, our material off-balance sheet arrangements and transactions include $48.7 million in letters of credit outstanding against our Credit Facility and $44.9 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily on certain firm transportation agreements. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 9of our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Critical Accounting Policies and Estimates
As of September 30, 2025, there have been no significant changes in our critical accounting policies from those disclosed in our 2024Annual Report on Form 10-K.
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