GULFPORT ENERGY CORP (GPOR) Business

ITEM 1. BUSINESS

Our Business

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. Gulfport's Predecessor was incorporated in the State of Delaware in July 1997. Our corporate headquarters are located in Oklahoma City, Oklahoma and shares of Gulfport's common stock trade on the New York Stock Exchange (“NYSE”) under the ticker symbol “GPOR”. Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow.

As of December 31, 2025, we had 4.3 Tcfe of proved reserves with a Standardized Measure of $3.4 billion and a PV-10 of $3.6 billion. See “Definitions” above for our definition of PV-10 (a non-GAAP financial measure) and “Oil, Natural Gas and NGL Reserves and Estimation” below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10.

Information About Us

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of our recent news releases. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On November 13, 2020, we, and certain of our subsidiaries, filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the NYSE under the symbol “GPOR”.

Business Strategy

Gulfport aims to create sustainable value through the economic development of our significant resource plays in the Utica/Marcellus and SCOOP operating areas. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, enhancing margins and operating efficiencies and returning capital to shareholders. To achieve 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. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet, return capital to shareholders and increase our resource depth through incremental leasehold opportunities that provide optionality to our future development plans.

2026 Outlook

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. In the Utica, we intend to complete drilling on approximately 18 gross (17.5 net) operated horizontal wells and commence sales on approximately 20 gross (19.5 net) operated horizontal wells. In the Marcellus, we intend to complete drilling on approximately 6 gross (5.6 net) and commence sales on approximately 4 gross (4.0 net) operated horizontal wells. In the SCOOP, we intend to complete drilling and commence sales on approximately 2 gross (1.7 net) operated horizontal wells. We expect to fund these expenditures with our operating cash flow and borrowings under our Credit Facility.

We expect this development program to result in approximately 1.030 to 1.055 Bcfe per day of production in 2026.

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Additionally, in 2026, we expect to continue returning capital to shareholders through our Repurchase Program. During 2025, we repurchased 1.8 million shares for $336.3 million at a weighted average price of $188.65 per share, leaving $579.6 million remaining on our Repurchase Program, which expires on December 31, 2026.

Operating Areas

Utica/Marcellus - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada. We have approximately 223,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet.

The Marcellus covers hydrocarbon-bearing rock formations that generally overlay the Utica in Ohio. We have identified approximately 35,000 net reservoir acres of our existing leasehold for Marcellus development and have 25 PUD Marcellus locations. In 2025 we drilled, completed, and turned to sales our first four well development pad in the Marcellus. Our Marcellus development area is approximately 3,500 to 4,500 feet shallower than the Utica.

During 2025, we produced approximately 841 MMcfe per day net to our interests in Utica/Marcellus and it accounted for approximately 81% of our total production.

SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 74,000 net reservoir acres (comprised of approximately 44,000 in the Woodford formation and approximately 30,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet.

During 2025, we produced approximately 197 MMcfe per day net to our interests in the SCOOP and it accounted for approximately 19% of our total production.

Oil, Natural Gas and NGL Reserves and Estimation

Reserve engineering is a subjective process of estimating volumes of economically recoverable oil, natural gas and NGL that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the reserve estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “Risk Factors” contained elsewhere in this Form 10-K.

As discussed above, the process of estimating oil, natural gas and NGL reserves is complex and requires significant judgment. As a result, we have developed internal policies and controls for estimating and recording reserves. Estimates of proved developed and undeveloped reserves and related information are presented in accordance with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules permit the use of reliable technologies to estimate and categorize reserves and require the use of the unweighted average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Reliable technologies were used to support the undeveloped locations in the Utica/Marcellus and SCOOP operating areas. The Company used public and proprietary geologic and engineering data to establish continuity of the formation and its producing properties. This data included performance data, seismic data, open hole log information, petro-physical analysis of log data, mud logs, log cross-sections, gas sample analysis, statistical analysis and measurements of total organic content and thermal maturity. In our development area, these data demonstrated consistent and continuous reservoir characteristics. Refer to Note 20 of our consolidated financial statements for more information pertaining to our proved reserves and the preparation of such estimates.

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Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with 30 years of reservoir and operations experience. In addition, our geoscience staff has approximately 58 years combined industry experience and our reservoir staff also has approximately 58 years combined experience.

During 2025, our total net natural gas, NGLs and oil proved reserves estimates attributable to the Company's interests were prepared by the Company and Netherland, Sewell & Associates, Inc. (“NSAI”) conducted an audit of the proved reserves as of December 31, 2025. NSAI is an independent petroleum engineering firm and was selected for their historical experience and geographic expertise in engineering similar resources. In the course of its audit, NSAI conducted a detailed review of properties making up approximately 86% of the total proved reserves and accounting for approximately 88% of the present worth of those reserves. The estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. A copy of the summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. Our internal staff of petroleum engineers and geoscience professionals work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. As needed, we provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits.

Reserve estimates for the year ended 2024 were prepared by the Company and audited by NSAI as of December 31, 2024. Reserve estimates for the year ended 2023 were prepared by NSAI for 100% of our operating areas.

Internal Controls Over Proved Reserve Estimates

Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us;

•verification of property ownership by our land department;

•audit of year-end reserve estimates by NSAI;

•direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer;

•review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

•provision of quarterly updates to our Board of Directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves;

•annual review by our Board of Directors of our year-end reserve report and year-over-year changes in our proved reserves;

•annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments, including the substitution, removal or deferral of PUD locations; and

•annual review and approval by our senior management and our Board of Directors of a multi-year development plan.

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The tables below set forth information as of December 31, 2025, with respect to our estimated proved developed and undeveloped oil, natural gas and NGL reserves, the associated estimated future net revenue, the PV-10 and the standardized measure. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.

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(1)    Includes approximately 26 Bcfe and 210 Bcfe of net developed and undeveloped reserves, respectively, located in the Marcellus target formation.

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(1)    Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2025, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2025. The prices used in our PV-10 measure were the average WTI Spot price of $66.01 per barrel and the average Henry Hub Spot price of $3.39 per MMBtu, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2025. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $219 million as of December 31, 2025.

Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.

A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.

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The following table summarizes the changes in our estimated proved reserves during 2025 (in Bcfe):

Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 701 Bcfe of proved reserves were primarily attributable to the continued development of our Utica/Marcellus and SCOOP acreage. We added 35 PUD locations in the Utica/Marcellus which included 28 Utica locations for 382 Bcfe and 7 Marcellus locations for 62 Bcfe. We also added 11 operated locations in the Utica to PDP which were not previously booked for 119 Bcfe. In the SCOOP, we added 6 PUD locations for 138 Bcfe.

Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs.

We experienced total downward revisions of 38 Bcfe in estimated proved reserves. These consisted of upward revisions of 255 Bcfe which were associated with commodity price changes. Commodity prices experienced volatility throughout 2025 and the 12-month unweighted average of the first-day-of-the-month price for natural gas increased from $2.13 per MMBtu for 2024 to $3.39 per MMBtu for 2025, the 12-month average WTI spot price for crude oil decreased from $76.32 per barrel for 2024 to $66.01 per barrel for 2025, and the calculated average weighted price for NGL over the remaining lives of the properties decreased from $31.30 per barrel for 2024 to $30.17 per barrel for 2025. Additionally, there were upward revisions of 161 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts throughout 2025. These were offset by downward revisions of 185 Bcfe and 129 Bcfe as a result of development schedule changes and PUD well design changes, respectively. The schedule changes moved the development of 9 Utica PUD locations and 4 SCOOP PUD locations beyond the SEC requirement of development within five years from initial booking and while these locations are excluded from our SEC reserves report, they remain in our longer-term development plan. Design changes primarily include well spacing and lateral length updates with a portion of these volumes now to be developed with locations outside of the SEC designated five-year development time frame. These development schedule and design changes reflect our ongoing commitment to optimizing the long-term plan to best develop our assets and maximize cash flow and overall economic returns. Finally, downward revisions of 141 Bcfe were a result of a combination of various economic assumptions and well performance updates.

Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2025, 2024 and 2023, and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information, in Note 20 of our consolidated financial statements.

Proved Undeveloped Reserves

As of December 31, 2025, our PUDs totaled 1,455 Bcf of natural gas, 16 MMBbl of oil and 50 MMBbl of NGL, for a total of 1,848 Bcfe. Approximately 82% and 18% of our PUD reserves at year-end 2025 were located in Utica/Marcellus and SCOOP, respectively. Our PUDs will be converted from undeveloped to developed as the applicable wells commence production or when there are no material incremental completion capital expenditures associated with such proved developed reserves.

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We record PUD locations only after a development plan has been approved by our senior management and Board of Directors to complete the associated development drilling within five years from the time of initial booking. The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved. These circumstances may include changes in commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells.

The following table summarizes the changes in our estimated proved undeveloped reserves during 2025 (in Bcfe):

Extensions and discoveries. Our extensions of approximately 582 Bcfe were primarily attributed to the addition of 41 PUD locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 35 PUD locations in the Utica/Marcellus and 6 PUD locations in the SCOOP.

Conversion to proved developed reserves. Our 2025 development activities resulted in the conversion of approximately 417 Bcfe into proved developed producing reserves, attributable to 31 PUD locations in the Utica/Marcellus and 11 PUD locations in the SCOOP. These 42 PUDs represent a conversion rate of 28% for 2025.

Revision of prior reserve estimates. We experienced total downward revisions of 177 Bcfe in estimated proved undeveloped reserves. This included 182 Bcfe and 84 Bcfe of downward revisions associated with changes in our development schedule changes and PUD well design changes, respectively. The schedule changes moved the development of 9 Utica PUD locations and 4 SCOOP PUD locations beyond the SEC requirement of development within five years from initial booking and while these locations are excluded from our SEC reserves report, they remain in our longer-term development plan. Design changes primarily include well spacing and lateral length updates with a portion of these volumes now to be developed with locations outside of the SEC designated five-year development time frame. These development schedule and design changes reflect our ongoing commitment to optimizing the long-term plan to best develop our assets and maximize cash flow and overall economic returns. These downward revisions were offset by upward revisions of 89 Bcfe in estimated proved reserves from a combination of changes including working interest and net revenue interest, well forecasts and price changes.

Costs incurred relating to the development of PUDs were approximately $235.9 million in 2025.

All PUD locations included in our 2025 reserve report are scheduled to be drilled within five years of initial booking.

As of December 31, 2025, 1.77% of our total proved reserves were classified as proved developed non-producing.

PV-10 Sensitivities

As noted above, our proved reserves at December 31, 2025, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for 2025 of $66.01 per barrel and $3.39 per MMBtu. Holding production and development costs constant, if SEC pricing were $72.61 per barrel and $3.73 per MMBtu, or a 10% increase, this would have resulted in an increase of 38 Bcfe of our total proved reserves and a $0.77 billion increase in PV-10 value at December 31, 2025. Holding production and development costs constant, if SEC pricing were $59.41 per barrel and $3.05 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 54 Bcfe of our total proved reserves and a $0.77 billion decrease in PV-10 value at December 31, 2025. For the low price scenario 132 PUDs were PV-10 economic.

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Acreage

The following table presents our total gross and net developed and undeveloped acres as of December 31, 2025:

Of our leases that are not held by production or held by other applicable lease provisions, most have a five-year primary term, and many include an optional right to extend the primary term for an additional three or five years. We manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our operations to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and voluntarily allowing certain leases to expire that are no longer part of our development plans. The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2025:

Productive Wells

The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2025:

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(1) We also have override/royalty interests in 182 wells with an average NRI of 0.6%, which are not material to our operations. Totals may not sum due to rounding.

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Drilling Activity

The following table sets forth information with respect to operated wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

The following table presents activity by operating area for the year ended December 31, 2025:

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(1)    Of the 27 gross operated wells drilled in 2025, 22 were completed as producing wells and five were in various stages of drilling and completion as of December 31, 2025.

(2)    The two gross operated wells that were drilled in 2025 were completed as producing wells as of December 31, 2025.

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Production, Prices and Production Costs

The following table presents our production volumes, average prices received and average production costs during the periods indicated (sales totals in thousands):

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The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2025:

Our Investments

Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2025, Grizzly had approximately 639,000 net acres under lease in the Athabasca, Peace River, and Cold Lake regions of Alberta, Canada. Grizzly's operations have been suspended since 2015. Additionally, Grizzly had no proved reserves as of December 31, 2025. We elected to cease funding capital calls in 2019, and we have no obligation to fund any future projects Grizzly may consider pursuing. Failure to fund capital calls will lead to continued dilution of our equity ownership interest in Grizzly.

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Marketing

The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for production from Gulfport-marketed wells. Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions. Oil production is sold under both spot and term transactions with the majority of our sales contracts being shorter term in nature.

We have entered into long-term gathering, processing and transportation contracts with various parties that reserve capacity for fixed, determinable quantities of production over specified periods of time. Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our firm transportation delivery commitments. These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets. See Note 17 of our consolidated financial statements for further discussion of our commitments.

Major Customers

Our total natural gas, oil and NGL sales, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the years ended December 31, 2025, 2024 and 2023 were as follows:

Competition

The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have. Competition can negatively impact our ability to successfully source quality vendors, service providers, employees and contractors to secure optimal pipeline access and end markets in which to sell our production, to acquire new properties, and our search for, and the development of, reserves. Many of our competitors not only explore for and produce oil and natural gas, but also have midstream and further downstream operations and market a variety of hydrocarbon products on a regional, national or worldwide basis. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include renewable sources such as wind or solar energy in addition to coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonality

Gulfport drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion, and field operations, as well as third-party midstream and downstream pipeline operations, which can impact overall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time.

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Title to Oil and Natural Gas Properties

It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations at the time we are preparing to develop the undeveloped leases and when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to certain imperfections in title, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations.

Regulation - Environment, Health and Safety

Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations

Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:

•reporting of workplace injuries and illnesses;

•industrial hygiene monitoring;

•worker protection and workplace safety;

•approval or permits to drill and to conduct operations;

•provision of financial assurances (such as bonds) covering drilling and well operations;

•calculation and disbursement of royalty payments and production taxes;

•seismic operations and data;

•location, drilling, cementing and casing of wells;

•well design and construction of pad and equipment;

•construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;

•method of completing wells;

•hydraulic fracturing;

•water withdrawal;

•well production and operations, including processing and gathering systems;

•emergency response, contingency plans and spill prevention plans;

•air emissions and fluid discharges;

•climate change;

•use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

•surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;

•plugging and abandoning of wells; and

•transportation of production.

Federal, state and local governments have periodically taken steps to reduce emissions of greenhouse gases (“GHG”). We consider the costs of environmental, safety and health protection and compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on policy and regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the “Risk Factors” described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters.

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Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the compulsory pooling or integration of tracts to facilitate exploration and development. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations often impose additional operational costs to us and can also limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to produce in commercial quantities from our properties.

Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (“BLM”) or Bureau of Indian Affairs (“BIA”) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. If future developments result in additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations. Permitting activities on federal lands are also subject to frequent delays.

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

We maintain a control of well insurance policy with a minimum limit of $25 million for single well limits and $37.5 million limit for multi-well pads. This policy insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million comprehensive general liability and umbrella insurance program. In addition, we maintain a $10 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate, as well as auto liability for our company vehicles. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

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We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans go through a technical review every five years and are updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean-up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean-up services during each of 2025, 2024 and 2023 were immaterial. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform.

Human Capital Management

Employees

As of December 31, 2025, we had 245 employees, an increase of approximately 5% from the 235 employees as of December 31, 2024. All of our employees are non-bargaining.

The attraction and retention of qualified employees continues to be one of our highest priorities. We focus on making substantive improvements to key areas that impact our employees. During 2025, we continued making significant investments in our talent management and retention processes, including increasing funds allocated to annual salary increases, short-term incentive payments, long-term incentive equity awards, 401(k) matches for eligible employees, and other enhancements to our benefits offerings. We remain committed to providing fair and competitive compensation programs and adequate development and advancement opportunities to our employees. We believe these practices serve as talent acquisition and retention tools, as our employees' continued engagement and commitment to the Company is critical to our success.

Over the course of 2025, Gulfport continued to develop and revise Company policies, including those intended to implement our Business Code of Conduct and Ethics, which provides a framework for how we interact with our employees, vendors and other stakeholders when conducting our operations. To that end, we provided all of our employees with annual trainings focused on the guidelines, rules, and principles that must be followed when acting on the Company's behalf. We remain committed to maintaining the highest standards of business ethics.

Health, Safety & Environment

Safety is at the forefront of everything we do. We have a robust annual training program, including environmental, health, and safety topics. Our safety program, WORK SAFE, is comprised of twelve key topics including critical tasks and cultural conditions. We hold regular safety briefings to discuss daily operations and routinely have safety stand-down meetings highlighting potential risks. Every employee is empowered to use their stop-work authority to cease operating if work is being performed in an unsafe manner. We monitor employee safety by establishing annual company-wide key safety metrics tied to leading indicators (i.e., incident reporting and investigations, hazard observations, safety and health meetings) and lagging indicators (i.e., injury rates and preventable motor vehicle accidents).

As part of our focus on continuous improvement, we monitor and communicate key environmental and safety metrics both internally and externally. Trend analysis guides us to make operational changes and policy updates as necessary to protect our employees, the public and the environment. We establish and carefully track key environmental and safety metrics that are a component of every employee’s incentive compensation opportunity annually.

We have established several programs to ensure that our employees and external partners are appropriately trained to perform the critical work we do safely and effectively. We continued to reinforce our WORK SAFE program and provided training to leaders on reinforcement strategies. Additionally, we continued the WORK GREEN program, which focuses on protecting the air, land and water where we operate and includes community-based volunteer events targeting environmental clean-up and habitat improvement initiatives. An environmental training on the elements of WORK GREEN was created and delivered to all employees.

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Training & Development

Gulfport invests in our employees' professional growth to build strong teams and develop leaders for today and the future. We build our dynamic team of industry-leading professionals by engaging them in interesting and rewarding work and providing training and development opportunities. We utilize training sessions with content developed by experts in the safety, legal, information security and regulatory compliance fields, and we offer a blend of training sessions through both computer-based modules and live, instructor-led sessions. We believe our training efforts support a compliant safety-first mindset in everything we do. We continue to provide professional and workplace-related training resources to employees through universities, electronic content services and specialized courses related to our industry through our tuition reimbursement program or third-party providers.

Executive Officers

John Reinhart, President, Chief Executive Officer and Director

On January 18, 2023, the Board of Directors appointed Mr. Reinhart, 57, as President, Chief Executive Officer and Director, effective as of January 24, 2023. Mr. Reinhart joined the Company with over two decades of oil and gas industry leadership experience. Most recently, he served as President, Chief Executive Officer and member of the board of directors of Montage Resources Corporation where he led actions that positioned Montage as an attractive strategic partner with sufficient scale, low debt profile and achievement of top-quartile operational and financial metrics. Mr. Reinhart previously served as President, Chief Executive Officer and member of the board of directors of Blue Ridge Mountain Resources and as Chief Operating Officer at Ascent Resources. He started his oil and gas career at Schlumberger before joining Chesapeake Energy Corporation, where he held operations roles with increasing responsibility. Mr. Reinhart began his career in the United States Army, serving tours in Panama and Iraq. Mr. Reinhart graduated from West Virginia University with a Bachelor of Science degree in Mechanical Engineering.

Michael Hodges, Executive Vice President and Chief Financial Officer

On April 3, 2023, the Board of Directors appointed Mr. Hodges, 47, as Executive Vice President and Chief Financial Officer. Most recently, Mr. Hodges served as Senior Vice President, Finance and Accounting at Leon Capital Group. Prior to joining Leon Capital, he was the Executive Vice President and Chief Financial Officer for Montage Resources Corporation until its merger with Southwestern Energy Company in November 2020. From 2012 until joining Montage Resources in 2018, Mr. Hodges served as the Chief Financial Officer for three upstream energy companies focused on near-term value creation through the acquisition and early-stage development of oil and natural gas resources. Mr. Hodges received his Bachelor of Business Administration in Finance from the University of Oklahoma and a Master of Science in Energy Management from Oklahoma City University and is a Certified Public Accountant in the State of Oklahoma.

Patrick Craine, Executive Vice President and Chief Legal and Administrative Officer

Mr. Craine, 53, has served as Chief Legal and Administrative Officer since June 2021 and joined Gulfport as Executive Vice President, General Counsel and Corporate Secretary in May 2019. Prior to joining the Company, Mr. Craine served as Deputy General Counsel – Chief Risk and Compliance Officer at Chesapeake Energy Corporation. Prior to joining Chesapeake in 2013, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused on securities and corporate regulatory matters and investigations. Before Mr. Craine entered private practice, he served as a lawyer with the U.S. Securities and Exchange Commission and the Financial Industry Regulatory Authority where he held leadership positions in their Oil and Gas Task Forces. Mr. Craine has over 25 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry. Mr. Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law.

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Matthew Rucker, Executive Vice President and Chief Operating Officer

Mr. Rucker, 40, joined Gulfport as the Senior Vice President of Operations in March 2023. On February 24, 2025, Matthew Rucker was promoted to Executive Vice President and Chief Operating Officer. He joined Gulfport from Javelin Energy Partners where he previously served as Vice President of Production Operations starting in August 2022. Mr. Rucker joined Javelin in July 2022 as the Vice President of Business Development. Prior to joining Javelin, Mr. Rucker served as the Executive Vice President, Chief Operating Officer for Montage Resources Corporation following Montage’s successful business combination transaction with Blue Ridge Mountain Resources in June 2020. Prior to Montage, Mr. Rucker served as Vice President, Resource Planning and Development of Blue Ridge from 2016 to 2020. Prior to joining Blue Ridge, Mr. Rucker served as a Production Superintendent for Chesapeake Energy Corporation from January 2014 to October 2016, overseeing Chesapeake’s Utica Shale production. As a member of Chesapeake’s Eastern Division leadership team, Mr. Rucker focused on the safe and efficient optimization of production in the Utica Shale and led an operating team of over 45 employees. During his service at Chesapeake, Mr. Rucker held several engineering positions in the Marcellus and Utica Shale asset teams within reservoir, primarily focused on strategic joint ventures, divestitures, acquisitions and resource development planning. Mr. Rucker received his Bachelor of Science degree in Petroleum Engineering from Marietta College and a Master of Business Administration in Energy from Texas Christian University. He serves on the Marietta College Industry Advisory Council and is a member of the Society of Petroleum Engineers.

Michael Sluiter, Senior Vice President of Reservoir Engineering

Mr. Sluiter, 53, joined Gulfport in December 2018 from Noble Energy, Inc., where he held various engineering and leadership positions from March 2007 to November 2018, including Permian Basin Business Unit Manager, Appalachian Reservoir Engineering Supervisor, and Business Development Engineering Advisor. Prior to joining Noble Energy, Mr. Sluiter worked for Santos Ltd., at the Australian headquarters in Adelaide and in Houston, primarily focused on petroleum engineering and planning functions Mr. Sluiter began his career as a wireline field services engineer for Schlumberger, Inc. and holds a Bachelor of Science degree in Chemical Engineering from the University of Sydney, Australia.

Lester Zitkus, Senior Vice President of Land

Mr. Zitkus, 60, has served as Senior Vice President of Land since January 2017 and joined the Company as Vice President of Land in March 2014. Prior to joining the Company, Mr. Zitkus served as an independent consultant from October 2013 to March 2014 and as Vice President of Land for Chesapeake Energy Corporation from May 2007 to October 2013. During his 20-year tenure with Equitable Resources Inc. (now EQT Corp.), he held various positions, including Vice President of Operations and Senior Vice President of Land, between 1987 and 2007. He holds a degree in Mineral Land Management from the University of Evansville. Mr. Zitkus is a member of the American Association of Professional Landmen and Past Regional Director of the Independent Petroleum Association of America.

There are no family relationships among our executive officers or between any executive officer and any member of the Board of Directors. Each executive officer serves at the discretion of the Board of Directors.

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