GPOR 10-K & 10-Q changes, risk factors and insider trading

•changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirusconcerns;

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2025future cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 20252026 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce. 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.

Our total principal debt was approximately $713.7$797.0 million at December 31, 2024.2025. We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties. Our financial commitments could have important consequences to our business, including, but not limited to, limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends, to repurchase shares of our common stock, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to make payments on our debt or to comply with restrictive terms of our debt. Higher levels of debt may make us more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing our credit facility and the indentures governing our senior notes contain a number of covenants that impose constraints on us, including requirements to comply with certain financial covenants and restrictions on our ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in consolidations, mergers and acquisitions. A downgrade in our credit rating could significantly increase our collateral requirements for commercial contracts and derivatives and restrict or limit our access to trade credit or capital. If commodity prices decline and we reduce our level of capital spending and production declines or we incur additional impairment expense or the value of our proved reserves declines, we may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in our debt instruments in the future. Refer to “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K and Note 4 of our consolidated financial statements for more information regarding the financial covenants and our Credit Facility.

We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proved oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting oil and NGL barrels to onegas Mcf of natural gasequivalents at the ratio of one barrel to six Mcf of natural gas to one barrel of oil.gas.

As of December 31, 2024,2025, we had a net operating loss, or NOL, carryforward of approximately $1.6$1.5 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under IRC Section 382, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate for the month in which such ownership change occurs. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period.

As of December 31, 2024,2025, approximately 47%43% of our total estimated proved reserves were PUDs and may not be ultimately developed or produced. Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports ofaudited ourby an independent petroleum engineersengineering firm assume that substantial capital expenditures are required to develop such reserves. Estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.

Our undeveloped leasehold acreage must be drilled before leasethe lease's expiration date in order to hold the acreagelease by production. In highly competitive markets for leasehold acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless,unless a lease contains an optional right to extend its term or, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although approximately 86%84% of our Utica/Marcellus acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 14%16% of our Utica/Marcellus acreage not held by production, approximately 7% will be subject to expiration in 2025,2026, 12%4% in 2026,2027, 9%28% in 20272028 and approximately 72%61% thereafter, although a portion of our Utica/Marcellus leases generally grant us the right to extend thesethe leasesterm for an additional three or five-year period. Approximately 99% of our SCOOP acreage is held by existing production; the remaining acreage is subject to expiration. Although we seek to actively manage our undeveloped leasehold properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop thecertain related properties.leases. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewalsthe cost of renewing expiring leases, we could lose portions of our leasehold acreage could expire and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.

We utilize multi-well pad drilling where practical. For example, in the Utica/Marcellus we drill multiple wells from a single pad. Wells drilled on a pad are not turned to sales until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells and the commencement of production from new wells and may negatively affect the production from existing offset wells, all of which may cause volatility in our operating results from period to period. Finally, delays in completion of wells may impact planned conversion of PUD reserves to PDP reserves.

We are not the operator of all of the properties in which we have an interest,interest and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploration activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including:

The largest purchaser of our oil and natural gas during the year ended December 31, 2024,2025, accounted for approximately 15%14% of our total natural gas, oil and NGL revenues. If this purchaser or one or more other significant purchasers, areis unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable. Further, the inability of one or more of our customers to pay amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for and wage rates of qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third partythird-party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of and increased costs for drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, have been and may become the target of cyberattacks or information security breaches that could result in the unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyberattack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s,customers’, supplier’ssuppliers’ or royalty owners’owners' data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

Our operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, in March 2024, the United States Environmental Protection Agency (“USEPA”), issued its final methane rules to reduce methane emissions from both new and existing oil and natural gas facilities and the Inflation Reduction Act of 2022 (“IRA 2022”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from the same facilities, the rule for which was finalized in November 2024. However, the methane emissions charge rule was repealed in February 2025 and the imposition of the charge under the IRA 2022 was postponed until 2034 under the One Big Beautiful Bill Act of July 2025. In December 2025, the USEPA issued a final rule extending several compliance deadlines and timeframes associated with the 2024 methane rules. Further, the Bureau for Land Management (BLM) issued a final Methane Waste Prevention Rule on April 10, 2024. The rule adds additional requirements for operators on federal and Indian leases and includes new air quality requirements along with waste prevention provisions. In November 2025, BLM announced it will delay enforcement of two provisions of the Waste Prevention Rule that had been scheduled to take effect in December 2025 as it reviews the underlying rule and considers revisions. Litigation challenging the 2024 rule is currently held in abeyance. Constrained supply chain for environmental control devices along with the significant estimated costs of compliance with these new and proposed rules could have a material impact on our operations. We may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.

Pipeline Safety. The pipeline assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areasareas.”. Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas. Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they could be significant, and any such costs incurred by our midstream service providers could result in increased midstream gathering and processing expenses for us. Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations.

Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. ThreeSeveral states (including New York, Maryland and Vermont)Vermont, have banned or imposed a moratorium on the use of high-volume hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Governments may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected.

Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane, and incentivizing energy conservation or the use of alternative energy sources. Policy makers at both the federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations or taxes on greenhouse gas emissions and encourage consumers to the alternative energy sources. The IRA 2022, both imposes new climate related requirements on oil and gas operations and appropriates significant federal funding for renewable energy initiatives. Also, for the first time ever, the law imposes a fee on GHG emissions from certain facilities. The emissions fee and funding provisions of the IRA 2022 could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business, results of operations and financial position. On January 26, 2024,Under the BidenTrump AdministrationAdministration, pausedhowever, approvalsthere forhas pendingbeen a shift away from the previous administration's GHG program. For example, in February 2025, the U.S. House and futureSenate applicationsapproved a joint resolution of disapproval under the Congressional Review Act to export liquified natural gas (LNG) on non-FTA countries. On January 20, 2025, President Trump issued an executive order reversingrepeal the pausemethane implementedemissions bycharge therule, Biden Administration, resuming the processing of export permit applications for new LNG projects. Additionally, in January 2025which President Trump signed executiveinto orderslaw. that,In amongSeptember other things, direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, and call upon2025, the USEPA to submitannounced a reportproposal onto end the continuingGHG applicabilityReporting Program for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal) and deferring reporting for petroleum and natural gas systems until 2034. In December 2025, the USEPA issued a final rule extending several compliance deadlines and timeframes associated with its 2024 methane rules. On February 12, 2026, the USEPA announced the repeal of its endangerment2009 finding“Endangerment for GHGsFinding” under the Clean Air ActAct, which found that GHGs endanger the public health and issuewelfare guidanceof oncurrent and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. The repeal calls into question EPA's authority to regulate GHGs, as well as EPA's prior scientific assessment of climate change risks. Litigation regarding the “socialrepeal costis anticipated and it is unclear how the repeal will impact EPA's regulation of carbon”GHG emissions going forward. However, state and local GHG initiatives may continue despite shifts in the federal approach to considerclimate whether such metric should be eliminated, and pause the disbursement of funds appropriated through the IRA 2022. The impact on these federal actions remain unclear.change.

In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our common units. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable to improve our sustainability performance and to meet the specific requirements to perform services for certain customers. If we are unable to meet the ESGsustainability standard or investment, lending, ratings, or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for ESG-focusedsustainability-focused activism, our cost of capital may increase, the price of our securities may be negatively impacted, and our reputation may also be negatively affected.

Endangered Species. The Endangered Species Act (“ESA”) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.

Increased attention to ESGsustainability matters may impact our business, financial results, or stock price.

In addition, we note that standardsStandards and expectations regarding carbon accounting and the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring both our emissions and our approaches to reducing emissions may be, either currently by some stakeholders or at some future point, considered inconsistent with common or best practices. A failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for ESGsustainability issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operations.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESGsustainability matters. These ratings are used by some investors to inform their investment and voting decisions. We may take certain actions to improve the ESGsustainability profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect. Unfavorable ESGsustainability ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example, legislative proposals have been introduced in the U.S. Congress in the past that, if enacted, would (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) repeal the percentage depletion allowance for oil and natural gas properties,properties and (iii) extend the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. In addition, at the state level, legislative changes imposing increased taxes on oil and gas production have periodically been considered in Ohio and Oklahoma. These proposed changes in the U.S. federal and state tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.

The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs as we collect, use, share,share and store personal data related to royalty owners. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, the California Consumer Privacy Act (“CCPA”), as amended by the California Privacy Rights Act (“CPRA”), establishes certain transparency rules and creates new data privacy rights for individuals, including limitations on our use of certain sensitive personal information and more ability for individuals to control the purposes for which their data is shared with third parties. The CPRA also provides for statutory fines for data security breaches or other CPRA violations. Meanwhile, many other states enacted, and others have considered, privacy laws like the CPRA. We will continue to monitor and assess the impact of these state laws, which may impose substantial penalties for violations, impose significant costs for investigations and compliance, require us to change our business practices, allow private class-action litigation and carry significant potential liability for our business should we fail to comply with any such applicable laws.

The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, future sales of additional stock and changes in our capital structure, compliance with governmental regulations and taxation laws, actual or anticipated variations in our operating results and cash flow, allocation of free cash flow including any determination by our board of directors regarding repurchasing stock, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A.1A of this Annual Report on Form 10-K.

The interests of these investors may not always coincide with the interests of the other holders of the common stock, and the concentration of control in these investors may limit other stockholders' ability to influence corporate matters. The concentration of ownership and voting power of these investors may also delay, defer or even prevent an acquisition by a third partythird-party or other change of control transactions of our Company. This may make some transactions more difficult or impossible without their support, even if such events are in the best interests of our other stockholders. In addition, the concentration of voting power may adversely affect the trading price and liquidity of the common stock.

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 20232024 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 20242025 to the year ended December 31, 2023.2024. Discussions of our results from 20222023 to 20232024 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, 2023.2024.

Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal propertiesoperations are located in eastern Ohio targetingtarget the Utica and Marcellus andformations in centraleastern OklahomaOhio targetingand the SCOOP Woodford and Springer formations.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.

On November 4, 2024, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $650.0 million to $1.0 billion and extended the authorization through December 31, 2025. During the year ended December 31, 2024,2025, the Company repurchased 1.21.8 million shares for $184.5$336.3 million at a weighted average price of $153.35$188.65 per share. As of December 31, 2024,2025, the Company repurchased 5.67.4 million shares for $584.1$920.4 million at a weighted average price of $104.88$125.19 per share since the inception of the Repurchase Program.

•Expanded common share repurchase program to $1.0$1.5 billion and returned $184.5$336.3 million to shareholders through the repurchase of 1.21.8 million shares (including the underlying shares of common stock into which the preferred stock was convertible) at a weighted average price of $153.35$188.65 per share.

•ExitedMaintained a strong balance sheet and low financial leverage, exiting the year with total liquidity of $899.7$806.1 million.

•Achieved MIQ certification for all AppalachianAppalachia assets for the secondthird consecutive year.

The Company's primary focus going into 20252026 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately supportenhance our expected free cash flow generation. We are committed to an emphasis on sustainability and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. 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 2024,2025, natural gas prices continued to be volatile as spot prices ranged from $1.21$2.65 to $13.20$9.86 per MMBtu. Henry Hub averaged $3.52 per MMBtu in 2025 vs $2.19 per MMBtu in 2024 vs $2.53 per MMBtu in 2023.2024. As we look into 2025,2026, 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 46%52% of our expected 20252026 gas production, at an average floor price of $3.59$3.74 per Mcf.

Our 20252026 capital expenditure program is expected to be in a range of $370$400 million to $395$430 million.million, including $35 million to $40 million on maintenance land and seismic investments.

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, compared to a net income of $1.5 billion for the year ended December 31, 2023.2024. The material changes that led to the decreaseincrease in net lossincome 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.

The decreaseincrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2024,2025, to the year ended December 31, 2023,2024, was primarily due to a 15%55% decreaseincrease in realized natural gas prices, partially offset by a 1%4% increasedecrease in sales volumes. The realized price change was primarily driven by the decreaseincrease in the average Henry Hub gas index from $2.74$2.27 per Mcf in the year ended December 31, 2023,2024, to $2.27$3.43 per Mcf during the year ended December 31, 2024.2025. The 1%4% increasedecrease in natural gas production was primarily due to ournatural 2023 and 2024 development programs in the Utica/Marcellusdeclines partially offset by naturalour declines2024 and limited2025 activitydevelopment inprograms and the SCOOP.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, 2024,2025, to the year ended December 31, 2023,2024, was due to a 7%55% increase in sales volumes, partially offset by a 5%15% decrease in realized oil prices. The 7%55% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids window.windows. The realized price change was primarily driven by the decrease in the average WTI crude index from $77.62$75.72 per barrel in the year ended December 31, 2023,2024, to $75.72$64.81 per barrel during the year ended December 31, 2024.2025.

The decreaseincrease in NGL sales without the impact of derivatives when comparing the year ended December 31, 2024,2025, to the year ended December 31, 2023,2024, was due to a 13%19% decreaseincrease in NGL sales volumes, partially offset by ana 8%1% increasedecrease in realized prices. The 13%19% decreaseincrease in NGL production was primarily due to naturalcommencement declinesof sales on new wells targeting the Utica and limitedMarcellus 2023liquids development in the SCOOP. The realized price change was primarily driven by the increase in the average Mont Belvieu NGL index from $30.07 per barrel in the year ended December 31, 2023, to $32.73 per barrel during the year ended December 31, 2024.windows.

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 year ended December 31, 20242025 compared to the year ended December 31, 2023,2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The net fair value lossesgains 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 compared to gains of $588.1 million for the year ended December 31, 2023.2024. 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, compared to cash receipts of $152.2 million for the year ended December 31, 2023.2024.

The increase in total LOE and per unit LOE for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, was primarily the result of increasedan productionincrease in water hauling, repairs and maintenance and labor expenses in our Utica/Marcellus as described above.operations.

The decrease in total and per unit taxes other than income for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, wasremained primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.consistent.

Transportation, gathering, processing and compression for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, increased inon a total and per unit basis primarily as a result of our smallan increase in the proportion of natural gas liquids and oil and condensate production.

Depreciation,The total and per unit depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, increased 2%decreased primarily due to a lower depletion rate resulting from a decline in our amortization base from the resultfull 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 ourunplanned, drillingthird-party midstream outages and developmentconstraints, activitiespartially duringoffset 2023by our 2024 and 2024.2025 development programs.

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 impairmentimpairments 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 $2.13$2.21 per MMBtu.MMBtu and $2.13 MMBtu, respectively.

We did not recordincur an impairment of oil and natural gas properties during any quarter in 2023.2025.

The increase in total and per unit general and administrative expenses for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, was primarily driven by increases in employee compensation and headcount.legal expense related to the matters disclosed in Note 18 of our consolidated financial statements.

Income Taxes (in thousands)

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, we had anour effective tax rate ofwas 18%17.66% and an income tax benefit of $56.1 million. For the year ended December 31, 2023, the Company's effective tax rate was (56)% and an income tax benefit of $525.2 million. The higher effective tax rate for the year ended December 31, 2024 is primarily related to the valuation allowance the Company released during the third quarter of 2023. See Note 10 of our consolidated financial statements for further discussion of our income tax benefit.expense.

For the year ended December 31, 2024,2025, 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.

As of December 31, 2024,2025, we had $1.5$1.8 million of cash and cash equivalents compared to $1.9$1.5 million as of December 31, 2023,2024, 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, compared to net working capital of $52.4 million as of December 31, 2023.2024. As of December 31, 2024,2025, 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, 2024,2025, was $713.7$797.0 million compared to $668.0$713.7 million as of December 31, 2023.2024. 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 20,19, 2025,2026, we had $3.1$2.1 million of cash and cash equivalents, $10.0$219.0 million borrowings under our Credit Facility, $63.9$48.7 million of letters of credit outstanding, $25.7 million of outstanding 2026 Senior Notes and $650.0 million of outstanding 2029 Senior Notes.

We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

Dividends on Preferred Stock. As discussed in Note 5 of our consolidated financial statements, holders of preferred stock arewere 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 currently havehad 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.

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock or senior notes are described below and under “"Risk Factors”" in Item 1A of our Annual Report on2025 Form 10-K for the year ended December 31, 2025.10-K.

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 11. 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 April 1, 2026 through June 30, 2026, January 1, 2026 through MarchJune 31,30, 20262026, April 1, 2025 through June 30, 2025 and January 1, 2025 through MarchJune 31,30, 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.

ResignationAppointment of JohnDomenic Reinhart,J. Dell’Osso, Jr., as President, Chief Executive Officer and Director

On May 1, 2026, the CompanyGulfport 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.

During the firstsecond quarter of 2026, we had the following notable achievements:

•Turned to sales five10 gross (4.969.5 net) operated wells.

•Repurchased 866,279392,222 shares for $172.8$70.0 million at a weighted average price of $199.45 per share.million.

Our total net production averaged approximately 996.8962.8 MMcfe per day during the three months ended MarchJune 31,30, 2026, as compared to 929.31,006.3 MMcfe per day during the three months ended MarchJune 31,30, 2025. Production per day increaseddecreased primarily due to natural declines and the timing of our 2025 and 2026 development programs.

Utica/Marcellus. We spud 97 gross (8.866.7 net) operated wells targeting the Utica and Marcellus formations and commenced sales from 5 gross (4.96 net) operated Utica wellsformation during the three months ended MarchJune 31,30, 2026. In addition, we commenced sales on 4 gross (3.9 net) operated Utica wells and 4 gross (4.0 net) operated Marcellus wells.

SCOOP. We did not spud 2 gross (1.60 net)any operated wells in the SCOOP during the three months ended MarchJune 31,30, 2026. We commenced sales on 2 gross (1.6 net) operated SCOOP wells.

Comparison of the Three Month Periods Ended MarchJune 31,30, 2026 and 2025

The following table summarizes our natural gas, oil and condensate and NGL production,production and related pricing for the three months ended MarchJune 31,30, 2026 as compared to the three months ended MarchJune 31,30, 2025. Some totals below may not sum or recalculate due to rounding.

The increasedecrease in natural gas sales without the impact of derivativesderivatives, when comparing the three months ended MarchJune 31,30, 2026,2026 to the three months ended MarchJune 31,30, 20252025, was due to a 31%17% increasedecrease in realized natural gas prices and ana 8%1% increasedecrease in sales volumes. The realized price change was primarily driven by the increasedecrease in the average Henry Hub gas index from $3.65$3.44 per Mcf in the three months ended MarchJune 31,30, 2025, to $5.04$2.89 per Mcf during the three months ended MarchJune 31,30, 2026. The 8%1% increasedecrease 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 derivativesderivatives, when comparing the three months ended MarchJune 31,30, 2026,2026 to the three months ended MarchJune 31,30, 2025, was due to a 29%46% decrease in sales volumes, partially offset by a 2%48% increase in realized prices. The 29%46% decrease in oil and condensate production was primarily due to natural declines partiallyand offsettiming byof 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$63.74 per barrel in the three months ended MarchJune 31,30, 2025, to $71.93$92.85 per barrel during the three months ended MarchJune 31,30, 2026.

The increase in NGL sales without the impact of derivativesderivatives, when comparing the three months ended MarchJune 31,30, 2026,2026 to the three months ended MarchJune 31,30, 2025, was due to a 15%22% increase in NGLrealized sales volumes,prices, partially offset by ana 11%13% decrease in realizedsales prices.volumes. The 15%13% increasedecrease in NGL production was primarily due to commencementnatural declines and timing of salesour on new wells targeting the Utica2025 and Marcellus2026 liquidsdevelopment windows.programs.

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 (loss) for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025, was primarily the result of changes in futures pricing for oil, natural gas, oil and NGLs during each period. See Note 10 of our consolidated financial statements for hedged volumes and pricing.

The increase in our total and per unit LOE for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025, was primarily the result of an increase in compression, waterrepairs haulingand maintenance and labor expenses.expenses in our Utica operations.

The increasedecrease in total and per unit taxes other than income for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025, was primarily related to ana increase in property taxes and an increasedecrease in natural gas sales as discussed above.

Transportation, gathering, processing and compression for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025, increased on a total and per unit basisdecreased primarily as a result of a 7%4% increasedecrease in total production volumes.

The total and per unit depreciation,Depreciation, depletion and amortization of our oil and gas properties for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025, increaseddecreased primarily due to lower production volumes. The decrease was partially offset by a higher depletion rate driven by our drilling and development activities subsequent to the firstsecond quarter of 2025.

Total interest expense for the three months ended MarchJune 31,30, 2026,2026 increased 15% compared to the three months ended MarchJune 31,30, 20252025, which was primarily due to higher borrowings on our Credit Facility. See Note 4 of our consolidated financial statements for further details regarding our long-term debt.

We recorded an income tax expense of $44.7$24.0 million and $51.7 million for the three months ended MarchJune 31,30, 2026 comparedand toJune income30, tax2025, benefit of $0.2 million for the three months ended March 31, 2025.respectively. See Note 14 of our consolidated financial statements for further discussion of our income tax expense.

For the three and six months ended MarchJune 31,30, 2026, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to our Credit Facility, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases and interest payments.

As of MarchJune 31,30, 2026, we had $2.9$1.1 million of cash and cash equivalents, $182.0$280.0 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 MarchJune 31,30, 2026 was $832.0$930.0 million.

As of AprilJuly 29,28, 2026 we had $2.5$3.5 million of cash and cash equivalents, $169.0$265.0 million in borrowings under our Credit Facility, $48.7 million of letters of credit outstanding and $650.0$650 million of outstanding 2029 Senior Notes.

Debt. As of MarchJune 31,30, 2026, we were in compliance with all financial covenants and had approximately $769.3$771.3 million of availability under the Credit Facility. The Credit Facility is subject to semi‑annual borrowing base redeterminations primarily based on projected future cash flows. See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt.