GULFPORT ENERGY CORP (GPOR)
SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas
SEC company page: https://www.sec.gov/edgar/browse/?CIK=874499. Latest filing source: 0001628280-26-011487.
Selected Fundamentals
| Metric | Value | Unit | FY | Filed |
|---|---|---|---|---|
| Revenue | 1,422,583,000 | USD | 2025 | 2026-02-25 |
| Net income | 427,810,000 | USD | 2025 | 2026-02-25 |
| Assets | 3,029,540,000 | USD | 2025 | 2026-02-25 |
Financials
Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000874499.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.
| Metric | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue | 708,990,000 | 385,910,000 | 1,320,303,000 | 1,551,701,000 | 1,563,126,000 | 866,542,000 | 1,331,112,000 | 1,791,702,000 | 958,131,000 | 1,422,583,000 | |
| Net income | -1,224,884,000 | -979,709,000 | 435,152,000 | 430,560,000 | -2,002,358,000 | -1,625,133,000 | 494,701,000 | 1,470,916,000 | -261,386,000 | 427,810,000 | |
| Operating income | -1,334,714,000 | -868,150,000 | 555,781,000 | 398,959,000 | -1,703,693,000 | -1,362,605,000 | 543,126,000 | 974,847,000 | -236,757,000 | 600,424,000 | |
| Diluted EPS | -12.27 | -7.97 | 2.41 | 2.45 | -12.49 | -10.14 | 20.32 | 66.46 | -14.72 | 21.48 | |
| Operating cash flow | 322,179,000 | 337,843,000 | 679,889,000 | 786,271,000 | 723,993,000 | 95,304,000 | 739,077,000 | 723,181,000 | 650,033,000 | 803,193,000 | |
| Assets | 4,223,145,000 | 5,807,752,000 | 6,051,036,000 | 3,882,819,000 | 2,539,871,000 | 2,252,990,000 | 2,534,479,000 | 3,267,613,000 | 2,865,697,000 | 3,029,540,000 | |
| Liabilities | 2,039,253,000 | 2,706,138,000 | 2,723,268,000 | 2,568,227,000 | 2,840,371,000 | 1,558,323,000 | 1,653,349,000 | 1,061,719,000 | 1,116,956,000 | 1,194,822,000 | |
| Stockholders' equity | 2,183,892,000 | 3,101,614,000 | 3,327,768,000 | 1,314,592,000 | -300,500,000 | 549,478,000 | 828,835,000 | 2,161,680,000 | 1,711,393,000 | 1,834,718,000 | |
| Cash and cash equivalents | 1,275,875,000 | 99,557,000 | 52,297,000 | 6,060,000 | 89,861,000 | 1,526,000 | 7,259,000 | 1,929,000 | 1,473,000 | 1,813,000 |
Ratios
| Metric | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Net margin | 32.96% | 27.75% | -128.10% | 37.16% | 82.10% | -27.28% | 30.07% | ||||
| Operating margin | 42.09% | 25.71% | -108.99% | 40.80% | 54.41% | -24.71% | 42.21% | ||||
| Return on equity | -44.86% | 14.03% | 12.94% | -152.32% | 59.69% | 68.05% | -15.27% | 23.32% | |||
| Return on assets | -23.20% | 7.49% | 7.12% | -51.57% | -63.98% | 19.52% | 45.02% | -9.12% | 14.12% | ||
| Liabilities / equity | 0.93 | 0.87 | 0.82 | 1.95 | 2.84 | 1.99 | 0.49 | 0.65 | 0.65 | ||
| Current ratio | 4.17 | 0.62 | 0.59 | 0.68 | 0.80 | 0.43 | 0.51 | 1.15 | 0.67 | 0.68 |
Financial Charts
Quarterly
Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000874499.json.
| Quarter | End Date | Revenue | Net Income | Diluted EPS | Method |
|---|---|---|---|---|---|
| 2022-Q2 | 2022-06-30 | 10.34 | reported discrete quarter | ||
| 2022-Q3 | 2022-09-30 | -1.01 | reported discrete quarter | ||
| 2023-Q1 | 2023-03-31 | 22.90 | reported discrete quarter | ||
| 2023-Q2 | 2023-03-31 | 523,054,000 | reported discrete quarter | ||
| 2023-Q2 | 2023-06-30 | 304,706,000 | 4.18 | reported discrete quarter | |
| 2023-Q3 | 2023-06-30 | 93,687,000 | reported discrete quarter | ||
| 2023-Q3 | 2023-09-30 | 266,667,000 | 27.37 | reported discrete quarter | |
| 2023-Q4 | 2023-12-31 | 489,108,000 | 245,731,000 | derived Q4 = FY annual - nine-month YTD | |
| 2024-Q1 | 2024-03-31 | 283,229,000 | 52,035,000 | 2.34 | reported discrete quarter |
| 2024-Q2 | 2024-03-31 | 52,035,000 | reported discrete quarter | ||
| 2024-Q2 | 2024-06-30 | 181,117,000 | -1.51 | reported discrete quarter | |
| 2024-Q3 | 2024-06-30 | -26,212,000 | reported discrete quarter | ||
| 2024-Q3 | 2024-09-30 | 253,912,000 | -0.83 | reported discrete quarter | |
| 2024-Q4 | 2024-12-31 | 239,873,000 | -273,242,000 | derived Q4 = FY annual - nine-month YTD | |
| 2025-Q1 | 2025-03-31 | 197,034,000 | -464,000 | -0.07 | reported discrete quarter |
| 2025-Q2 | 2025-03-31 | -464,000 | reported discrete quarter | ||
| 2025-Q2 | 2025-06-30 | 447,616,000 | 9.12 | reported discrete quarter | |
| 2025-Q3 | 2025-06-30 | 184,466,000 | reported discrete quarter | ||
| 2025-Q3 | 2025-09-30 | 379,745,000 | 4.45 | reported discrete quarter | |
| 2025-Q4 | 2025-12-31 | 398,188,000 | 132,415,000 | derived Q4 = FY annual - nine-month YTD | |
| 2026-Q1 | 2026-03-31 | 437,532,000 | 165,822,000 | 8.87 | reported discrete quarter |
Quarterly Charts
Macro Cross-References
- CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
- UNRATE - Unemployment Rate
- FEDFUNDS - Federal Funds Effective Rate
- CES0500000003 - Average Hourly Earnings of All Employees, Total Private
- DFEDTARU - Federal Funds Target Range - Upper Limit
- DFEDTARL - Federal Funds Target Range - Lower Limit
- DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
- DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
- DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
- DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
- T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
- CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
- CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
- CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
- CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
- PCEPI - Personal Consumption Expenditures: Chain-type Price Index
- PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
- PPIACO - Producer Price Index by Commodity: All Commodities
- T10YIE - 10-Year Breakeven Inflation Rate
- U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
- PAYEMS - All Employees, Total Nonfarm
- CIVPART - Labor Force Participation Rate
- EMRATIO - Employment-Population Ratio
- UNEMPLOY - Unemployed
- CE16OV - Employment Level
- ICSA - Initial Claims
- JTSJOL - Job Openings: Total Nonfarm
- JTSQUR - Quits: Total Nonfarm
- GDPC1 - Real Gross Domestic Product
- A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
- INDPRO - Industrial Production: Total Index
- TCU - Capacity Utilization: Total Index
- HOUST - New Privately-Owned Housing Units Started: Total Units
- PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
- RSAFS - Advance Retail Sales: Retail Trade
- PCE - Personal Consumption Expenditures
- DSPIC96 - Real Disposable Personal Income
- PSAVERT - Personal Saving Rate
- M2SL - M2
- BOPGSTB - U.S. International Trade in Goods and Services: Balance
- MSPUS - Median Sales Price of Houses Sold for the United States
- HSN1F - New One Family Houses Sold: United States
- RHORUSQ156N - Homeownership Rate in the United States
- TTLCONS - Total Construction Spending: Total Construction in the United States
- RRVRUSQ156N - Rental Vacancy Rate in the United States
- TOTALSL - Total Consumer Credit Owned and Securitized
- REVOLSL - Revolving Consumer Credit Owned and Securitized
- DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
- GDP - Gross Domestic Product
- GPDI - Gross Private Domestic Investment
- GCE - Government Consumption Expenditures and Gross Investment
- PCEC - Personal Consumption Expenditures
- NETEXP - Net Exports of Goods and Services
- GFDEBTN - Federal Debt: Total Public Debt
- GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
- FYFSD - Federal Surplus or Deficit
- FGRECPT - Federal Government Current Receipts
- FGEXPND - Federal Government: Current Expenditures
- MANEMP - All Employees, Manufacturing
- USCONS - All Employees, Construction
- USTRADE - All Employees, Retail Trade
- USFIRE - All Employees, Financial Activities
- USGOVT - All Employees, Government
- AWHAETP - Average Weekly Hours of All Employees, Total Private
- DGORDER - Manufacturers' New Orders: Durable Goods
- NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
- BUSINV - Total Business Inventories
- EXPGS - Exports of Goods and Services
- IMPGS - Imports of Goods and Services
- IR - Import Price Index (End Use): All Commodities
- PPIFIS - Producer Price Index by Commodity: Final Demand
Latest quarter (10-Q)
Latest 10-Q source: 0001628280-26-031073.
ITEM 2.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, 2025 (“2025 Form 10-K”), and analyzes the changes in the results of operations between the periods of January 1, 2026 through March 31, 2026 and January 1, 2025 through March 31, 2025. 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 operations target the Utica and Marcellus formations in eastern Ohio and the SCOOP Woodford and Springer formations in central Oklahoma. 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 generally 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 Resignation of John Reinhart, as President, Chief Executive Officer and Director On March 6, 2026, our President, Chief Executive Officer (“CEO”) and Director, John Reinhart, elected to depart the Company and resigned from our Board of Directors, effective immediately. Following his departure, our Board of Directors established an Office of the Chairman to assume executive oversight while we conduct a search for a permanent CEO. The Office of the Chairman is led by Timothy J. Cutt, Chairman of the Board and former CEO from May 2021 through January 2023, and includes Michael Hodges, Executive Vice President and Chief Financial Officer; Matthew Rucker, Executive Vice President and Chief Operating Officer; and Patrick Craine, Executive Vice President and Chief Legal and Administrative Officer. Credit Facility On May 1, 2026, the Company completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion and elected commitments were increased to $1.1 billion. Share Repurchase Program During the three months ended March 31, 2026, the Company repurchased 866,279 shares for $172.8 million at a weighted average price of $199.45 per share. As of March 31, 2026, the Company repurchased 8.2 million shares for $1.1 billion at a weighted average price of $133.02 per share since the inception of the Repurchase Program. Tariffs and Trading Relationships In 2025 and 2026, the U.S. government threatened, announced and, in certain cases, rescinded, tariffs on several foreign jurisdictions and imports into the United States, which led, and may continue to lead, to the imposition of retaliatory tariffs and other measures taken by foreign jurisdictions. There is significant uncertainty as to the scope and durability of existing and future tariff measures, as well as the ultimate effects of the tariffs on economic conditions. 27 Table of Contents Geopolitical and Market Conditions Ongoing geopolitical instability, including the conflict involving Iran and heightened tensions in the Middle East, has contributed to increased volatility in global energy markets. While the Company does not have operations or assets in the affected regions, these events may impact commodity prices, global supply and demand dynamics, and overall market conditions. As of the date of this filing, the Company has not experienced any material direct impacts to its operations, liquidity, or financial condition as a result of these developments. 2026 Operational and Financial Highlights During the first quarter of 2026, we had the following notable achievements: •Reported total net production of 996.8 MMcfe per day. •Turned to sales five gross (4.96 net) operated wells. •Generated $292.9 million of operating cash flows. •Repurchased 866,279 shares for $172.8 million at a weighted average price of $199.45 per share. •Exited the quarter with total liquidity of $772.2 million. 2026 Production and Drilling Activity Production Volumes Three Months Ended March 31, 2026 Three Months Ended March 31, 2025 Natural gas (Mcf/day) Utica & Marcellus 782,851 686,964 SCOOP 122,919 150,851 Total 905,770 837,816 Oil and condensate (Bbl/day) Utica & Marcellus 2,533 3,861 SCOOP 1,205 1,420 Total 3,738 5,282 NGL (Bbl/day) Utica & Marcellus 5,827 3,495 SCOOP 5,605 6,467 Total 11,432 9,962 Combined (Mcfe/day) Utica & Marcellus 833,010 731,105 SCOOP 163,776 198,175 Total 996,786 929,280 Totals may not sum or recalculate due to rounding. Our total net production averaged approximately 996.8 MMcfe per day during the three months ended March 31, 2026, as compared to 929.3 MMcfe per day during the three months ended March 31, 2025. Production per day increased primarily due to the timing of our 2025 and 2026 development programs. Utica/Marcellus. We spud 9 gross (8.86 net) operated wells targeting the Utica and Marcellus formations and commenced sales from 5 gross (4.96 net) operated Utica wells during the three months ended March 31, 2026. SCOOP. We spud 2 gross (1.60 net) operated wells in the SCOOP during the three months ended March 31, 2026. 28 Table of Contents RESULTS OF OPERATIONS Comparison of the Three Month Periods Ended March 31, 2026 and 2025 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 March 31, 2026 as compared to the three months ended March 31, 2025. Some totals below may not sum or recalculate due to rounding. Three Months Ended March 31, 2026 Three Months Ended March 31, 2025 Natural gas sales Natural gas production volumes (MMcf) 81,519 75,403 Natural gas production volumes (MMcf) per day 906 838 Total sales $ 399,530 $ 281,506 Average price without the impact of derivatives ($/Mcf) $ 4.90 $ 3.73 Impact from settled derivatives ($/Mcf) $ (0.68) $ (0.12) Average price, including settled derivatives ($/Mcf) $ 4.22 $ 3.61 Oil and condensate sales Oil and condensate production volumes (MBbl) 336 475 Oil and condensate production volumes (MBbl) per day 4 5 Total sales $ 22,338 $ 31,259 Average price without the impact of derivatives ($/Bbl) $ 66.40 $ 65.76 Impact from settled derivatives ($/Bbl) $ (4.80) $ 1.06 Average price, including settled derivatives ($/Bbl) $ 61.60 $ 66.82 NGL sales NGL production volumes (MBbl) 1,029 897 NGL production volumes (MBbl) per day 11 10 Total sales $ 31,477 $ 30,817 Average price without the impact of derivatives ($/Bbl) $ 30.59 $ 34.37 Impact from settled derivatives ($/Bbl) $ 0.75 $ (1.53) Average price, including settled derivatives ($/Bbl) $ 31.34 $ 32.84 Natural gas, oil and condensate and NGL sales Natural gas equivalents (MMcfe) 89,711 83,635 Natural gas equivalents (MMcfe) per day 997 929 Total sales $ 453,345 $ 343,582 Average price without the impact of derivatives ($/Mcfe) $ 5.05 $ 4.11 Impact from settled derivatives ($/Mcfe) $ (0.63) $ (0.12) Average price, including settled derivatives ($/Mcfe) $ 4.42 $ 3.99 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.27 $ 0.24 Average taxes other than income ($/Mcfe) $ 0.10 $ 0.08 Average transportation, gathering, processing and compression ($/Mcfe) $ 1.01 $ 0.99 Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe) $ 1.38 $ 1.31 29 Table of Contents Natural Gas, Oil and Condensate and NGL Sales (in thousands) Three Months Ended March 31, 2026 Three Months Ended March 31, 2025 % Change Natural gas $ 399,530 $ 281,506 42 % Oil and condensate 22,338 31,259 (29) % NGL 31,477 30,817 2 % Natural gas, oil and condensate and NGL sales $ 453,345 $ 343,582 32 % The increase in natural gas sales without the impact of derivatives when comparing the three months ended March 31, 2026, to the three months ended March 31, 2025 was due to a 31% increase in realized natural gas prices and an 8% increase in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $3.65 per Mcf in the three months ended March 31, 2025, to $5.04 per Mcf during the three months ended March 31, 2026. The 8% increase in natural gas production was primarily due to the timing of our 2025 and 2026 development programs. The decrease in oil and condensate sales without the impact of derivatives when comparing the three months ended March 31, 2026, to the three months ended March 31, 2025, was due to a 29% decrease in sales volumes, partially offset by a 2% increase in realized prices. The 29% decrease in oil and condensate production was primarily due to natural declines partially offset by our 2025 and 2026 development programs. The realized price change was primarily driven by the increase in the average WTI crude index from $71.42 per barrel in the three months ended March 31, 2025, to $71.93 per barrel during the three months ended March 31, 2026. The increase in NGL sales without the impact of derivatives when comparing the three months ended March 31, 2026, to the three months ended March 31, 2025, was due to a 15% increase in NGL sales volumes, partially offset by an 11% decrease in realized prices. The 15% 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 March 31, 2026 Three Months Ended March 31, 2025 Natural gas derivatives - fair value gains (losses) $ 57,593 $ (133,664) Natural gas derivatives - settlement losses (55,906) (9,025) Total gains (losses) on natural gas derivatives 1,687 (142,689) Oil and condensate derivatives - fair value losses (9,880) (6) Oil and condensate derivatives - settlement (losses) gains (1,616) 504 Total (losses) gains on oil and condensate derivatives (11,496) 498 NGL derivatives - fair value losses (6,772) (2,988) NGL derivatives - settlement gains (losses) 768 (1,369) Total losses on NGL derivatives (6,004) (4,357) Total losses on natural gas, oil and NGL derivatives $ (15,813) $ (146,548) 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 change in the total loss for the three months ended March 31, 2026 compared to the three months ended March 31, 2025, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. See Note 10 of our consolidated financial statements for hedged volumes and pricing. 30 Table of Contents Lease Operating Expenses (in tho [Excerpt truncated for page length; source filing is linked above.]
Latest 10-K MD&A
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with Item 8. “Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2024 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2025 to the year ended December 31, 2024. Discussions of our results from 2023 to 2024 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2024. 40 Table of Contents Index to Financial Statements Overview Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal operations target the Utica and Marcellus formations in eastern Ohio and the SCOOP Woodford and Springer formations in central Oklahoma. 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 generally 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 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 year ended December 31, 2025, the Company repurchased 1.8 million shares for $336.3 million at a weighted average price of $188.65 per share. As of December 31, 2025, the Company repurchased 7.4 million shares for $920.4 million at a weighted average price of $125.19 per share since the inception of the Repurchase Program. Credit Facility On October 30, 2025, the Company entered into the Borrowing Base Reaffirmation Agreement and Fifth Amendment to Credit Agreement (the “Fifth Amendment”). The facility provides for a borrowing base of $1.1 billion and aggregate elected commitments of $1.0 billion. Tariffs and Trading Relationships In 2025 and 2026, the U.S. government threatened, announced and, in certain cases, rescinded, tariffs on several foreign jurisdictions and imports into the United States, which led, and may continue to lead, to the imposition of retaliatory tariffs and other measures taken by foreign jurisdictions. There is significant uncertainty as to the scope and durability of existing and future tariff measures, as well as the ultimate effects of the tariffs on economic conditions. 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. 41 Table of Contents Index to Financial Statements 2025 Operational and Financial Highlights During 2025, we had the following notable achievements: •Reported total net production of 1,039 MMcfe per day. •Generated $803.2 million of operating cash flows. •Turned to sales 32 gross operated (31.8 net) wells. •Redeemed outstanding preferred stock, simplifying our capital structure and eliminating future dividend obligations on the preferred stock. •Expanded common share repurchase program to $1.5 billion and returned $336.3 million to shareholders through the repurchase of 1.8 million shares (including the underlying shares of common stock into which the preferred stock was convertible) at a weighted average price of $188.65 per share. •Maintained a strong balance sheet and low financial leverage, exiting the year with total liquidity of $806.1 million. •Achieved MIQ certification for all Appalachia assets for the third consecutive year. •Reported year-end estimated net proved reserves of 4.3 Tcfe. Business and Industry Outlook The Company's primary focus going into 2026 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately enhance our expected free cash flow generation. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities. In 2025, natural gas prices continued to be volatile as spot prices ranged from $2.65 to $9.86 per MMBtu. Henry Hub averaged $3.52 per MMBtu in 2025 vs $2.19 per MMBtu in 2024. As we look into 2026, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 52% of our expected 2026 gas production, at an average floor price of $3.74 per Mcf. Our 2026 capital expenditure program is expected to be in a range of $400 million to $430 million, including $35 million to $40 million on maintenance land and seismic investments. 42 Table of Contents Index to Financial Statements Results of Operations Comparison of the Year Ended December 31, 2025 and 2024 We reported net income of $427.8 million for the year ended December 31, 2025, compared to a net loss of $261.4 million for the year ended December 31, 2024. The material changes that led to the increase in net income are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding. Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands) Year Ended December 31, 2025 Year Ended December 31, 2024 Natural gas (MMcf/day) Utica & Marcellus production volumes 777 810 SCOOP production volumes 150 157 Total production volumes 927 968 Total sales $ 1,056,429 $ 714,160 Average price without the impact of derivatives ($/Mcf) $ 3.12 $ 2.02 Impact from settled derivatives ($/Mcf) $ 0.14 $ 0.80 Average price, including settled derivatives ($/Mcf) $ 3.26 $ 2.82 Oil and condensate (MBbl/day) Utica & Marcellus production volumes 5 2 SCOOP production volumes 1 2 Total production volumes 6 4 Total sales $ 133,644 $ 101,589 Average price without the impact of derivatives ($/Bbl) $ 59.12 $ 69.64 Impact from settled derivatives ($/Bbl) $ 4.04 $ 0.11 Average price, including settled derivatives ($/Bbl) $ 63.16 $ 69.75 NGL (MBbl/day) Utica & Marcellus production volumes 6 3 SCOOP production volumes 6 8 Total production volumes 12 10 Total sales $ 133,454 $ 112,855 Average price without the impact of derivatives ($/Bbl) $ 29.30 $ 29.56 Impact from settled derivatives ($/Bbl) $ (0.07) $ (0.56) Average price, including settled derivatives ($/Bbl) $ 29.23 $ 29.00 Total (MMcfe/day) Utica & Marcellus production volumes 841 842 SCOOP production volumes 197 212 Total production volumes 1,039 1,054 Total sales $ 1,323,527 $ 928,604 Average price without the impact of derivatives ($/Mcfe) $ 3.49 $ 2.41 Impact from settled derivatives ($/Mcfe) $ 0.15 $ 0.73 Average price, including settled derivatives ($/Mcfe) $ 3.64 $ 3.14 43 Table of Contents Index to Financial Statements Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Natural gas $ 1,056,429 $ 714,160 48 % Oil and condensate 133,644 101,589 32 % NGL 133,454 112,855 18 % Total natural gas, oil and condensate and NGL sales $ 1,323,527 $ 928,604 43 % The increase in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was primarily due to a 55% increase in realized natural gas prices, partially offset by a 4% decrease in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $2.27 per Mcf in the year ended December 31, 2024, to $3.43 per Mcf during the year ended December 31, 2025. The 4% 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 year ended December 31, 2025, to the year ended December 31, 2024, was due to a 55% increase in sales volumes, partially offset by a 15% decrease in realized oil prices. The 55% 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 $75.72 per barrel in the year ended December 31, 2024, to $64.81 per barrel during the year ended December 31, 2025. The increase in NGL sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was due to a 19% increase in NGL sales volumes, partially offset by a 1% decrease in realized prices. The 19% 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) The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2025 and 2024, represented approximately 73% and 80%, respectively, of our total sales volumes for the applicable year. Year Ended December 31, 2025 Year Ended December 31, 2024 Natural gas derivatives - fair value gains (losses) $ 39,010 $ (251,019) Natural gas derivatives - settlement gains 47,705 284,626 Total gains on natural gas derivatives 86,715 33,607 Oil and condensate derivatives - fair value (losses) gains (3,468) 2,351 Oil and condensate derivatives - settlement gains 9,124 166 Total gains on oil and condensate derivatives 5,656 2,517 NGL derivatives - fair value gains (losses) 7,017 (4,442) NGL derivatives - settlement losses (332) (2,155) Total gains (losses) on NGL derivatives 6,685 (6,597) Total gains on natural gas, oil and NGL derivatives $ 99,056 $ 29,527 44 Table of Contents Index to Financial Statements 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 change in the total gain for the year ended December 31, 2025 compared to the year ended December 31, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The net fair value gains of our hedging program totaled $42.6 million for the year ended December 31, 2025 compared to losses of $253.1 million for the year ended December 31, 2024. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements. Our hedging program generated cash receipts of $56.5 million for the year ended December 31, 2025, compared to cash receipts of $282.6 million for the year ended December 31, 2024. Lease Operating Expenses (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Lease operating expenses Utica & Marcellus $ 61,661 $ 48,321 28 % SCOOP 22,581 21,791 4 % Total lease operating expenses $ 84,242 $ 70,112 20 % Lease operating expenses per Mcfe Utica & Marcellus $ 0.20 $ 0.16 25 % SCOOP 0.31 0.28 11 % Total lease operating expenses per Mcfe $ 0.22 $ 0.18 22 % The increase in total LOE and per unit LOE for the year ended December 31, 2025, compared to the year ended December 31, 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) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Production taxes $ 21,408 $ 19,385 10 % Property taxes 5,527 8,174 (32) % Other 2,973 2,178 37 % Total taxes other than income $ 29,908 $ 29,737 1 % Total taxes other than income per Mcfe $ 0.08 $ 0.08 — % The total and per unit taxes other than income for the year ended December 31, 2025, compared to the year ended December 31, 2024, remained consistent. Transportation, Gathering, Processing and Compression (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Transportation, gathering, processing and compression $ 358,938 $ 351,237 2 % Transportation, gathering, processing and compression per Mcfe $ 0.95 $ 0.91 4 % Transportation, gathering, processing and compression for the year ended December 31, 2025, compared to the year ended December 31, 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 production. 45 Table of Contents Index to Financial Statements Depreciation, Depletion and Amortization (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Depreciation, depletion and amortization of oil and gas properties $ 302,024 $ 324,078 (7) % Depreciation, depletion and amortization of other property and equipment 2,138 1,645 30 % Total depreciation, depletion and amortization $ 304,162 $ 325,723 (7) % Total depreciation, depletion and amortization per Mcfe $ 0.80 $ 0.84 (5) % The total and per unit depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2025, compared to the year ended December 31, 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. Our production decreased 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. Impairment of Oil and Natural Gas Properties At September 30, 2024 and December 31, 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 in the third quarter and $342.7 million in the fourth quarter of 2024. The impairments 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. The 12-month average trailing price for natural gas in the third quarter and fourth quarter of 2024 was $2.21 per MMBtu and $2.13 MMBtu, respectively. We did not incur an impairment of oil and natural gas properties during any quarter in 2025. General and Administrative Expenses (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change General and administrative expenses, gross $ 84,004 $ 82,478 2 % Reimbursed from third parties (16,269) (14,582) 12 % Capitalized general and administrative expenses (25,247) (25,338) — % General and administrative expenses, net $ 42,488 $ 42,558 — % General and administrative expenses, net per Mcfe $ 0.11 $ 0.11 — % The increase in total and per unit general and administrative expenses for the year ended December 31, 2025, compared to the year ended December 31, 2024, was primarily driven by increases in employee compensation and legal expense related to the matters disclosed in Note 18 of our consolidated financial statements. 46 Table of Contents Index to Financial Statements Interest Expense (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Interest on 2026 Senior Notes $ 777 $ 31,417 (98) % Interest on 2029 Senior Notes 43,875 13,163 233 % Interest on Credit Facility 9,390 14,143 (34) % Amortization of loan costs 5,258 4,208 25 % Capitalized interest (6,154) (4,771) 29 % Other 1,131 1,822 (38) % Total interest expense $ 54,277 $ 59,982 (10) % Interest expense per Mcfe $ 0.14 $ 0.16 (13) % Total interest expense for the year ended December 31, 2025, decreased 10% compared to the year ended December 31, 2024. The decrease was primarily due to lower borrowings and a reduced interest rate on our Credit Facility. In the third quarter of 2024, we retired the 2026 Senior Notes and issued the 2029 Senior Notes. Although the interest rate on the 2029 Senior Notes is lower than that of the 2026 Senior Notes, the higher principal balance largely offset the effect of the lower interest rate, resulting in little overall impact on interest expense between periods. We capitalized $6.2 million of interest during the period, compared to $4.8 million in the prior year. See Note 4 of our consolidated financial statements for further details regarding our Credit Facility, issuance of the 2029 Senior Notes and retirement of the 2026 Senior Notes. 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 tendered 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 On July 4, 2025, the OBBBA, which includes a broad range of tax reform provisions, was signed into law in the United States. We completed our assessment of the OBBBA's provision and incorporated the applicable impacts into our current tax expense and deferred tax assets and liabilities. The provisions did not have a significant effect on the Company’s tax positions for the current period. For the year ended December 31, 2025, our effective tax rate was 21.26% and an income tax expense of $115.5 million. For the year ended December 31, 2024, our effective tax rate was 17.66% and an income tax benefit of $56.1 million. See Note 10 of 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 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 year ended December 31, 2025, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, interest payments, dividend payments on our preferred stock and discretionary acreage acquisitions. 47 Table of Contents Index to Financial Statements 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 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes. As of December 31, 2025, we had $1.8 million of cash and cash equivalents compared to $1.5 million as of December 31, 2024, and a net working capital deficit of $115.9 million as of December 31, 2025, compared to net working deficit of $114.2 million as of December 31, 2024. As of December 31, 2025, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2025, was $797.0 million compared to $713.7 million as of December 31, 2024. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes. As of February 19, 2026, we had $2.1 million of cash and cash equivalents, $219.0 million borrowings under our Credit Facility, $48.7 million of letters of credit outstanding and $650.0 million of outstanding 2029 Senior Notes. Debt. In May 2025, we redeemed the remaining $25.7 million principal amount of our 8.00% senior unsecured notes due 2026 at par. As of December 31, 2025, we had $650.0 million of our 6.75% senior unsecured notes due 2029, which is classified as long‑term on our consolidated balance sheet. Based on amounts outstanding at year‑end, anticipated annual cash interest payments on our fixed‑rate debt total approximately $43.9 million. In October 2025, we entered into the Fifth Amendment to our Credit Agreement, which reaffirmed the borrowing base at $1.1 billion and maintained elected commitments at $1.0 billion, with a maturity date of September 12, 2028. As of December 31, 2025, we had $147.0 million of borrowings outstanding, no letters of credit issued, and were in compliance with all financial covenants. At year‑end, we had approximately $804.3 million of availability under the Credit Facility, which remains subject to semi‑annual borrowing base redeterminations based primarily on projected future cash flows, with the next scheduled redetermination occurring in the spring of 2026. We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt through privately negotiated transactions, open market repurchases, tender offers or otherwise, but we are under no obligation to do so. See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt. Dividends on Preferred Stock. As discussed in Note 5 of 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. During the years ended December 31, 2025 and 2024, the Company paid $1.7 million and $4.2 million, respectively, of cash dividends to holders of our preferred stock. No cash dividends were paid after the Redemption Date. Supplemental Guarantor Financial Information. 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. 48 Table of Contents Index to Financial Statements 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 7A. “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities. Subsequent to December 31, 2025 and as of February 19, 2026, we entered into the following natural gas, oil, and NGL derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Average Price Natural Gas (MMBtu/d) ($/MMBtu) 2026 Swaps NYMEX Henry Hub 36,603 $3.86 2027 Swaps NYMEX Henry Hub 40,000 $3.80 2027 Basis Swaps TETCO M2 50,000 $(0.80) 2027 Basis Swaps Rex Zone 3 30,000 $(0.22) 2027 Basis Swaps NGPL TXOK 30,000 $(0.34) Oil (Bbl/d) ($/Bbl) 2026 Costless Collars NYMEX WTI 1,125 $55.00 / $71.18 2027 Costless Collars NYMEX WTI 300 $55.00 / $68.00 Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2025 (in thousands): Payment due by period Contractual Obligations Total 2026 2027-2028 2029-2030 2031 and Thereafter Long-term debt(1): Principal $ 797,000 $ — $ 147,000 $ 650,000 $ — Interest 200,084 53,048 103,161 43,875 — Firm transportation and gathering contracts(2) 1,037,663 138,975 269,992 253,586 375,110 Other operational commitments(3) 16,409 16,409 — — — Operating lease liabilities(4) 571 561 10 — — Total contractual cash obligations(5) $ 2,051,727 $ 208,993 $ 520,163 $ 947,461 $ 375,110 _____________________ (1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 4 of our consolidated financial statements for a description of our long-term debt. (2) See Note 17 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments. (3) See Note 17 of our consolidated financial statements for a description of our other operational commitments. (4) See Note 9 of our consolidated financial statements for a description of our operating lease liabilities. (5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of our consolidated financial statements, respectively. 49 Table of Contents Index to Financial Statements 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 December 31, 2025, our material off-balance sheet arrangements and transactions include $48.7 million in letters of credit outstanding against our Credit Facility and $45.3 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase material and services to be used in future drilling and completion activities. 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 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued. 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 year ended December 31, 2025, the Company's incurred capital expenditures totaled $526.1 million related to operated activities, of which $428.4 million related to drilling and completion activities, $34.8 million related to maintenance leasehold and land investment and $62.9 million related to discretionary acreage acquisitions. Our drilling and completion capital expenditures for 2026 are currently estimated to be in the range of $365 million to $390 million. Also, we currently expect to spend approximately $35 million to $40 million in 2026 for maintenance land and seismic investments, primarily focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2026, 2027 and 2028. We expect this capital program to result in approximately 1.030 to 1.055 Bcfe per day of production in 2026. Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2025, WTI prices ranged from $55.44 to $80.73 per barrel and the Henry Hub spot market price of natural gas ranged from $2.65 to $9.86 per MMBtu. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. If the prices of oil and natural gas continue to be volatile, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities. See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2025. 50 Table of Contents Index to Financial Statements Sources and Uses of Cash The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2025 and 2024 (in thousands): Year Ended December 31, 2025 Year Ended December 31, 2024 Net cash provided by operating activities $ 803,193 $ 650,033 Additions to oil and natural gas properties (527,569) (454,098) Debt activity, net 83,298 32,761 Debt issuance and loan commitment fees (35) (14,933) Repurchases of common stock (304,961) (184,477) Redemption of preferred stock (32,423) — Net cash payments on performance vesting restricted stock units (12,297) — Dividends on preferred stock (1,666) (4,230) Shares exchanged for tax withholdings (5,579) (23,614) Other (1,621) (1,898) Net change in cash and cash equivalents $ 340 $ (456) Cash and cash equivalents at end of period $ 1,813 $ 1,473 Net cash provided by operating activities. Net cash provided by operating activities was $803.2 million for the year ended December 31, 2025, compared to $650.0 million for the year ended December 31, 2024. The increase was primarily the result of a increase in our natural gas revenues. Additions to oil and natural gas properties. During the year ended December 31, 2025, we spud 24 gross (23.9 net) operated wells and commenced sales from 30 gross (30.0 net) operated wells targeting the Utica and Marcellus formations for a total cost incurred of approximately $401.0 million. During the year ended December 31, 2025, we did not spud any operated wells and commenced sales from 2 gross (1.8 net) operated wells in the SCOOP for a total incurred cost of approximately $27.5 million. Additionally, the Company incurred $34.8 million related to maintenance leasehold and land investment and $62.9 million related to discretionary acreage acquisitions. 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 year ended December 31, 2025 and 2024, were as follows (in thousands): Year Ended December 31, 2025 Year Ended December 31, 2024 Oil and Natural Gas Property Cash Expenditures: Drilling and completion costs $ 404,239 $ 325,129 Leasehold acquisitions 95,610 102,630 Other 27,720 26,339 Total oil and natural gas property expenditures $ 527,569 $ 454,098 Debt activity, net. During the year ended December 31, 2025, the Company had $1.4 billion and $1.2 billion in borrowings and repayments, respectively, on its Credit Facility. In May 2025, the Company redeemed the remaining $25.7 million principal amount of its 2026 Senior Notes at par. As of February 19, 2026, the Company had $219.0 million in borrowings outstanding on its Credit Facility. Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred $14.9 million of debt issuance and loan commitment fees, related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity. 51 Table of Contents Index to Financial Statements Repurchases of common stock. During the year ended December 31, 2025, the Company repurchased 1.8 million shares for approximately $336.3 million under the Repurchase Program at a weighted average price of $188.65 per share. For the same period in 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 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 5 of our consolidated financial statements for further discussion of the redemption of preferred stock. Net cash payments on performance vesting restricted stock units. During the year ended December 31, 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 7 of our consolidated financial statements. Dividends on preferred stock. During the year ended December 31, 2025, the Company paid $1.7 million of cash dividends to holders of our preferred stock compared to $4.2 million in the year ended December 31, 2024. No cash dividends were paid after the Redemption Date. Shares exchanged for tax withholdings. During the year ended December 31, 2025, the Company paid $5.6 million of shares exchanged for tax withholdings compared to $23.6 million in the year ended December 31, 2024. The decrease was primarily due to lower aggregate fair value of vested awards as discussed in Note 7 of our consolidated financial statements. 52 Table of Contents Index to Financial Statements Critical Accounting Policies and Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors. Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2025. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. The Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2025 and recognized ceiling test impairments of $373.2 million during 2024. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting. Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information. Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized. 53 Table of Contents Index to Financial Statements Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals. Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.