Insiders ranked by realized 90-day signed return on their open-market trades at Gulfport Energy Corp. Minimum 3 scored trades. Returns are signed - a sale followed by a rally counts against the insider.
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is 0.03pp more bullish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
+0.00pp
Flat
Net-tone change vs last year's 10-K.
MD&A
+0.06pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
adversely+1
litigation+1
delay+1
prevention+1
downgrade+1
Positive rising
greater+1
gain+1
advantage+1
efficient+1
enabling+1
Risk Factors (Item 1A)
12,537 words
ITEM 1A.
RISK FACTORS
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a summary of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.
Financial, Liquidity and Commodity Price Risks
Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, cash flows, profitability, future rate of growth, production and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for natural gas and, to a lesser extent, oil and NGL. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low natural gas, oil and NGL prices can affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas, oil and NGL prices may result in ceiling test write-downs of our oil and natural gas properties.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
unplanned+2
outages+2
depletion+1
volatile+1
impairments+1
Positive rising
beautiful+2
enhance+1
MD&A (Item 7)
7,191 words
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with Item 8. “Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2024 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2025 to the year ended December 31, 2024. Discussions of our results from 2023 to 2024 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2024.
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Overview
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal operations target the Utica and Marcellus formations in eastern Ohio and the SCOOP Woodford and Springer formations in central Oklahoma. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating and returning capital to shareholders. To these goals, we generally allocate capital to projects we believe offer the rate of return and we deploy drilling and completion techniques and technologies in our development efforts.
Historically, the markets for natural gas, oil and NGL have been volatile, and they are likely to continue to be volatile. For example, during 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. During 2025, WTI prices ranged from $55.44 to $80.73 per barrel and the Henry Hub spot market price of natural gas ranged from $2.65 to $9.86 per MMBtu.
Wide fluctuations in natural gas, oil and NGL prices may result from factors that are beyond our control, including:
• domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;
• the level of prices, and expectations about future prices, of oil and natural gas;
• changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns;
• the cost of exploring for, developing, producing and delivering oil and natural gas;
• the expected rates of declining current production;
• the price and availability of alternative fuels;
• technological advances and changing consumer attitudes affecting energy consumption;
• risks associated with operating drilling rigs;
• the effectiveness of worldwide conservation measures;
• the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
• the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
• U.S. exports of oil, natural gas, liquefied natural gas and NGL;
• the price and level of foreign imports and exports, including as a result of U.S. trade policy;
• the nature and extent of domestic and foreign governmental regulations and taxes;
• the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil price and production controls;
• political or economic instability or armed conflict in oil and natural gas producing regions;
• weather conditions;
• acts of terrorism; and
• domestic and global economic conditions.
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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 future cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2026 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 commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.
Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which is structured under floating rate terms. As such, our interest expense is sensitive to fluctuations in the SOFR benchmark. For the year ended December 31, 2025, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 6.53%. A 1% increase in the average interest rate would increase our interest expense by approximately $1.5 million based on outstanding borrowings under our Credit Facility at December 31, 2025. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our Credit Facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition. As of December 31, 2025, we did not hedge our interest rate risk.
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Our debt and other financial commitments may limit our financial and operating flexibility.
Our total principal debt was approximately $797.0 million at December 31, 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.
Our development, acquisition and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves.
Historically, we have financed capital expenditures primarily with cash flow from operations and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:
• our proved reserves;
• the volume of oil and natural gas we are able to produce from existing wells;
• the prices at which oil and natural gas are sold;
• our ability to acquire, locate and produce economically new reserves; and
• our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital through a variety of means. We cannot guarantee that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves. In addition, we may be unable to implement our development plan, complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
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Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.
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 gas equivalents at the ratio of one barrel to six Mcf of gas.
Under the full cost method of accounting for oil and gas properties, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or non-cash write-down is required. A ceiling test impairment can result in a significant loss for a particular period. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. Future non-cash asset impairments could negatively affect our results of operations.
A change of control could limit our use of net operating losses to reduce future taxable income.
As of December 31, 2025, we had a net operating loss, or NOL, carryforward of approximately $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.
Industry, Business and Operational Risks
The oil and gas development, exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.
We face competition in every aspect of our business, including buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and may have greater access to the capital and credit markets. Many of these companies not only explore for and produce oil and natural gas but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
In addition, the oil and gas industry is characterized by rapid technological change and the introduction of new products and services. Competitors that develop or adopt new technologies more quickly may gain a significant advantage, which could require us to incur substantial costs to remain competitive. Some industry participants have greater financial, technical, and personnel resources, enabling them to implement innovations sooner and more effectively than we can. Our ability to respond to these changes in a timely and cost efficient manner is uncertain, and if technologies we rely on become obsolete, our business, financial condition, or results of operations could be materially and adversely affected.
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Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
As of December 31, 2025, approximately 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 audited by an independent petroleum engineering 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.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2025 present value is based on a $3.39 per MMBtu of gas price and a $66.01 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
Actual future net revenues from our oil and natural gas properties will also be affected by factors such as:
• actual prices we receive for oil and natural gas;
• the amount and timing of actual production;
• supply of and demand for oil and natural gas; and
• changes in governmental regulations or taxation.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
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Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We acquire unproven properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas, oil and NGL, costs associated with producing natural gas, oil and NGL and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations. All costs of development and exploratory drilling activities are capitalized under the full cost method, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices decrease.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
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Part of our strategy involves using the latest available horizontal drilling and completion techniques; therefore, the results of our planned drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the development activities we employ, such as offset drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of offset drilling, adjacent wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Our undeveloped leasehold acreage must be drilled before the lease's expiration date in order to hold the lease 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 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 84% of our Utica/Marcellus acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 16% of our Utica/Marcellus acreage not held by production, approximately 7% will be subject to expiration in 2026, 4% in 2027, 28% in 2028 and approximately 61% thereafter, although a portion of our Utica/Marcellus leases generally grant us the right to extend the term 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 certain 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 the cost of renewing expiring leases, 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.
Oil and natural gas operations are uncertain and involve substantial costs and risks. Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
• unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
• loss of drilling fluid circulation;
• equipment failures or accidents;
• fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;
• risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground
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migration of fracturing fluids, including chemical additives;
• adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures, which may be exacerbated by climate change;
• issues with title or in receiving governmental permits or approvals;
• restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
• environmental hazards or liabilities, including liabilities for environmental damage caused by previous owners of properties purchased by us;
• restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
• shortages or delays in the availability of services or delivery of equipment; and
• unexpected or unforeseen changes in regulatory policy, and political or public opinions.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities.
While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, cybersecurity breaches, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves.
We utilize multi-well pad drilling where practical. 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 our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
We are not the operator of all of the properties in which we have an 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 timing and amount of capital expenditures;
• the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
• the operator's expertise and financial resources;
• approval of other participants in drilling wells;
• selection of technology; and
• the rate of production of the reserves.
In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.
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Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids.
All of our producing properties are located in eastern Ohio and central Oklahoma, making us vulnerable to risks associated with operating in only these regions.
Our largest fields by production are located in eastern Ohio and central Oklahoma. As a result, we may be disproportionatelyexposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes, tornados or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available.
The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.
The largest purchaser of our oil and natural gas during the year ended December 31, 2025, accounted for approximately 14% of our total natural gas, oil and NGL revenues. If this purchaser or one or more other significant purchasers, is 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 unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
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-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 operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines, trucks and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations.
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With respect to our Utica/Marcellus acreage where we are focusing a portion of our exploration and development activity, operations may be delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider. Capital constraints could limit the construction of new pipelines and gathering systems and the providing or expansion of trucking services by third parties in the Utica/Marcellus and the other areas in which we operate. As a result, we may experience delays or curtailments in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in or curtail our wells awaiting a pipeline connection or capacity or sell natural gas, oil or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.
A portion of our natural gas, oil and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.
We have contracts with some of our third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments under which we are obligated to pay certain fees on minimum volumes regardless of actual volume throughput. As of December 31, 2025, our aggregate long-term contractual obligation under these agreements was approximately $1.0 billion. These fees could be significant and may have a material adverse effect on our results of operations.
A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, tariffs, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the United States financial markets have contributed to economic volatility and diminished expectations for the global economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity and financial condition.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have in the past precipitated, and may in the future precipitate, an economic slowdown.
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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
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 sufferdisruptions 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 customers’, suppliers’ or royalty 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.
In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient. As cyberattacks continue to evolve, including those leveraging artificial intelligence, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, new laws and regulations governing data privacy, cybersecurity, and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
We may engage in acquisition and divestiture activities that involve substantial risks.
We may make acquisitions that complement or expand our current areas of operations. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
• mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;
• difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
• unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio or to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or businesses and potential post-closingclaims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing.
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Environmental, Legal and Regulatory Risks
We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.
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 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. Litigationchallenging 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.
In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations. As of January 2025, however, the Trump Administration issued a series of executive orders that signal a shift in the United States' energy polices, including directing federal agencies to identify and exercise emergency authorities to facilitate conventional energy production, transportation, and refining, and call for the use of emergency regulations to expedite energy infrastructure projects, promote energy exploration and production on federal lands and waters, and mandate a review of existing regulations that may burden domestic energy development.
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 areas.” 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.
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Seismic Activity. Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the OCC issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing or water disposal activities. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
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. Several states including New York, Maryland and 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.
We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greateropposition to hydraulic fracturing, including litigation.
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. Under the Trump Administration, however, there has been a shift away from the previous administration's GHG program. For example, in February 2025, the U.S. House and Senate approved a joint resolution of disapproval under the Congressional Review Act to repeal the methane emissions charge rule, which President Trump signed into law. In September 2025, the USEPA announced a proposal to end the GHG Reporting 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 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current 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 repeal is anticipated and it is unclear how the repeal will impact EPA's regulation of GHG emissions going forward. However, state and local GHG initiatives may continue despite shifts in the federal approach to climate change.
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States in which we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level or other initiatives to incentivize the use of renewable energy could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
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 sustainability 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 sustainability-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.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
Severe weather events, such as storms, hurricanes, droughts, or floods, which may be exacerbated by climate change, could have an adverse effect on our operations and could increase our costs. Potential adverse effects could include damages to our facilities, the costs of less efficient or non-routine operating practices necessitated by weather events, or increased costs for insurance coverage. If climate changes result in more intense or frequent severe weather events, the physical and disruptive effects could have a material adverse impact on our operations and assets.
Air Emissions. The US Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminalpenalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
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.
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Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, including in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells.
In our Utica/Marcellus and SCOOP operations, we make an effort to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active. While our objective is to recycle or share 100% of all produced water, we do inject water into third-party commercially operated disposal wells in line with all state and federal mandated practices and cease produced water recycle whenever fracture stimulation operations are idle once sharing opportunities with other operators have been exhausted. In the state of Ohio, all water used during drilling operations is disposed of through injection into third-party salt water disposal wells regulated by applicable state agencies.
Increased attention to sustainability matters may impact our business, financial results, or stock price.
Standards 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 sustainability 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 sustainability matters. These ratings are used by some investors to inform their investment and voting decisions. We may take certain actions to improve the sustainability profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect. Unfavorable sustainability 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.
Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
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 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.
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Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.
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 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.
Any failure, or perceived failure, by us to comply with applicable data protection laws could result in heightened risk of litigation, including private rights of action, and proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyber incidents or attacks, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Risks Associated with an Investment in Us
The market price of our securities is subject to volatility.
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 of this Annual Report on Form 10-K.
Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.
A significant percentage of our common stock is held by a single investor. In connection with our emergence from bankruptcy protection in 2021, we entered into the Registration Rights Agreement pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of our common stock by such investors. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.
We cannot predict the effect that future sales of our common stock will have on the price at which the common stock trades. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.
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Certain of our stockholders own a significant portion of our outstanding equity securities and their interests may not always coincide with the interests of other holders of the common stock.
A large percentage of our equity is held by a relatively small number of investors. As a result, these investors could have significant influence over all matters presented to our stockholders for approval, including election and removal of our directors, change in control transactions and the outcome of all actions requiring majority stockholder approval.
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-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.
There may be future dilution of our common stock, which could adversely affect the market price of our common stock.
We are not restricted from issuing additional shares of our common stock. In the future, we may issue shares of our common stock to raise cash for future capital expenditures, acquisitions or for general corporate purposes. We may also issue securities that are convertible into, exchangeable for or that represent the right to receive our common stock. Lastly, we currently issue restricted stock units and performance vesting restricted stock units to certain employees and directors as part of their compensation. Any of these events will dilute our shareholders' ownership interest in Gulfport and may reduce our earnings per share and have an adverse effect on the price of our common stock.
Our amended and restated certificate of incorporation provides, subject to certain exceptions, that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.
Our amended and restated certificate of incorporation provides, subject to limited exceptions, that the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors or officers to us, our stockholders, our creditors or other constituents; (iii) any action asserting a claim against us, any director or our officers arising pursuant to any provision of the DGCL, our certificate of incorporation or our by-laws; or (iv) any action asserting a claim against us, any director or our officers that is governed by the internal affairs doctrine. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors or officers or stockholders which may discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision contained in our certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our business, financial condition and results of operations.
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Recent Developments
Share Repurchase Program and Redemption of Preferred Stock
On August 4, 2025, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $1.0 billion to $1.5 billion (including the redemption of preferred stock noted below) and extended the authorization through December 31, 2026.
On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. During the period between the date of notice of the redemption and the Redemption Date, 28,907 shares of preferred stock were converted into approximately 2.1 million shares of common stock. On the Redemption Date, the Company redeemed the remaining 2,449 shares of preferred stock for cash totaling $31.3 million. Additionally, direct transaction-related costs of $1.1 million were incurred as part of the redemption.
During the year ended December 31, 2025, the Company repurchased 1.8 million shares for $336.3 million at a weighted average price of $188.65 per share. As of December 31, 2025, the Company repurchased 7.4 million shares for $920.4 million at a weighted average price of $125.19 per share since the inception of the Repurchase Program.
Credit Facility
On October 30, 2025, the Company entered into the Borrowing Base Reaffirmation Agreement and Fifth Amendment to Credit Agreement (the “Fifth Amendment”). The facility provides for a borrowing base of $1.1 billion and aggregate elected commitments of $1.0 billion.
Tariffs and Trading Relationships
In 2025 and 2026, the U.S. government threatened, announced and, in certain cases, rescinded, tariffs on several foreign jurisdictions and imports into the United States, which led, and may continue to lead, to the imposition of retaliatory tariffs and other measures taken by foreign jurisdictions. There is significant uncertainty as to the scope and durability of existing and future tariff measures, as well as the ultimate effects of the tariffs on economic conditions.
One Big Beautiful Bill Act
On July 4, 2025, the President signed into law the legislation commonly referred to as the One Big Beautiful Bill Act (“OBBBA”), which introduces significant changes to U.S. federal tax law. Key provisions of the OBBBA that are relevant to the Company include modifications to the limitations on the deductibility of interest expense under Section 163(j) of the Internal Revenue Code and adjustments to bonus depreciation rules.
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2025 Operational and Financial Highlights
During 2025, we had the following notable achievements:
• Reported total net production of 1,039 MMcfe per day.
• Generated $803.2 million of operating cash flows.
• Turned to sales 32 gross operated (31.8 net) wells.
• Redeemed outstanding preferred stock, simplifying our capital structure and eliminating future dividend obligations on the preferred stock.
• Expanded common share repurchase program to $1.5 billion and returned $336.3 million to shareholders through the repurchase of 1.8 million shares (including the underlying shares of common stock into which the preferred stock was convertible) at a weighted average price of $188.65 per share.
• Maintained a strong balance sheet and low financial leverage, exiting the year with total liquidity of $806.1 million.
• Achieved MIQ certification for all Appalachia assets for the third consecutive year.
• Reported year-end estimated net proved reserves of 4.3 Tcfe.
Business and Industry Outlook
The Company's primary focus going into 2026 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately enhance our expected free cash flow generation. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.
In 2025, natural gas prices continued to be volatile as spot prices ranged from $2.65 to $9.86 per MMBtu. Henry Hub averaged $3.52 per MMBtu in 2025 vs $2.19 per MMBtu in 2024. As we look into 2026, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 52% of our expected 2026 gas production, at an average floor price of $3.74 per Mcf.
Our 2026 capital expenditure program is expected to be in a range of $400 million to $430 million, including $35 million to $40 million on maintenance land and seismic investments.
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Results of Operations
Comparison of the Year Ended December 31, 2025 and 2024
We reported net income of $427.8 million for the year ended December 31, 2025, compared to a net loss of $261.4 million for the year ended December 31, 2024. The material changes that led to the increase in net income are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)
Year Ended December 31, 2025
Year Ended December 31, 2024
Natural gas (MMcf/day)
Utica & Marcellus production volumes
SCOOP production volumes
Total production volumes
Total sales
Average price without the impact of derivatives ($/Mcf)
Impact from settled derivatives ($/Mcf)
Average price, including settled derivatives ($/Mcf)
Oil and condensate (MBbl/day)
Utica & Marcellus production volumes
SCOOP production volumes
Total production volumes
Total sales
Average price without the impact of derivatives ($/Bbl)
Impact from settled derivatives ($/Bbl)
Average price, including settled derivatives ($/Bbl)
NGL (MBbl/day)
Utica & Marcellus production volumes
SCOOP production volumes
Total production volumes
Total sales
Average price without the impact of derivatives ($/Bbl)
Impact from settled derivatives ($/Bbl)
Average price, including settled derivatives ($/Bbl)
Total (MMcfe/day)
Utica & Marcellus production volumes
SCOOP production volumes
Total production volumes
Total sales
Average price without the impact of derivatives ($/Mcfe)
Impact from settled derivatives ($/Mcfe)
Average price, including settled derivatives ($/Mcfe)
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Year Ended December 31, 2025
Year Ended December 31, 2024
% Change
Natural gas
Oil and condensate
NGL
Total natural gas, oil and condensate and NGL sales
The increase in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was primarily due to a 55% increase in realized natural gas prices, partially offset by a 4% decrease in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $2.27 per Mcf in the year ended December 31, 2024, to $3.43 per Mcf during the year ended December 31, 2025. The 4% decrease in natural gas production was primarily due to natural declines partially offset by our 2024 and 2025 development programs and the impact of unplanned, third-party midstream outages and constraints.
The increase in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was due to a 55% increase in sales volumes, partially offset by a 15% decrease in realized oil prices. The 55% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids windows. The realized price change was primarily driven by the decrease in the average WTI crude index from $75.72 per barrel in the year ended December 31, 2024, to $64.81 per barrel during the year ended December 31, 2025.
The increase in NGL sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was due to a 19% increase in NGL sales volumes, partially offset by a 1% decrease in realized prices. The 19% increase in NGL production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids windows.
Natural Gas, Oil and NGL Derivatives (in thousands)
The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2025 and 2024, represented approximately 73% and 80%, respectively, of our total sales volumes for the applicable year.
Year Ended December 31, 2025
Year Ended December 31, 2024
Natural gas derivatives - fair value gains (losses)
Natural gas derivatives - settlement gains
Total gains on natural gas derivatives
Oil and condensate derivatives - fair value (losses) gains
Oil and condensate derivatives - settlement gains
Total gains on oil and condensate derivatives
NGL derivatives - fair value gains (losses)
NGL derivatives - settlement losses
Total gains (losses) on NGL derivatives
Total gains on natural gas, oil and NGL derivatives
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We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The change in the total gain for the year ended December 31, 2025 compared to the year ended December 31, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The net fair value gains of our hedging program totaled $42.6 million for the year ended December 31, 2025 compared to losses of $253.1 million for the year ended December 31, 2024. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements. Our hedging program generated cash receipts of $56.5 million for the year ended December 31, 2025, compared to cash receipts of $282.6 million for the year ended December 31, 2024.
Lease Operating Expenses (in thousands, except per unit)
Year Ended December 31, 2025
Year Ended December 31, 2024
% Change
Lease operating expenses
Utica & Marcellus
SCOOP
Total lease operating expenses
Lease operating expenses per Mcfe
Utica & Marcellus
SCOOP
Total lease operating expenses per Mcfe
The increase in total LOE and per unit LOE for the year ended December 31, 2025, compared to the year ended December 31, 2024, was primarily the result of an increase in water hauling, repairs and maintenance and labor expenses in our Utica operations.
Taxes Other Than Income (in thousands, except per unit)
Year Ended December 31, 2025
Year Ended December 31, 2024
% Change
Production taxes
Property taxes
Other
Total taxes other than income
Total taxes other than income per Mcfe
The total and per unit taxes other than income for the year ended December 31, 2025, compared to the year ended December 31, 2024, remained consistent.
Transportation, Gathering, Processing and Compression (in thousands, except per unit)
Year Ended December 31, 2025
Year Ended December 31, 2024
% Change
Transportation, gathering, processing and compression
Transportation, gathering, processing and compression per Mcfe
Transportation, gathering, processing and compression for the year ended December 31, 2025, compared to the year ended December 31, 2024, increased on a total and per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate production.
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Depreciation, Depletion and Amortization (in thousands, except per unit)
Year Ended December 31, 2025
Year Ended December 31, 2024
% Change
Depreciation, depletion and amortization of oil and gas properties
Depreciation, depletion and amortization of other property and equipment
Total depreciation, depletion and amortization
Total depreciation, depletion and amortization per Mcfe
The total and per unit depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2025, compared to the year ended December 31, 2024, decreased primarily due to a lower depletion rate resulting from a decline in our amortization base from the full cost ceiling test impairments recorded during 2024, combined with a decrease in our production. Our production decreased primarily due to natural declines and the impact of unplanned, third-party midstream outages and constraints, partially offset by our 2024 and 2025 development programs.
Impairment of Oil and Natural Gas Properties
At September 30, 2024 and December 31, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million in the third quarter and $342.7 million in the fourth quarter of 2024. The impairments resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the third quarter and fourth quarter of 2024 was $2.21 per MMBtu and $2.13 MMBtu, respectively.
We did not incur an impairment of oil and natural gas properties during any quarter in 2025.
General and Administrative Expenses (in thousands, except per unit)
Year Ended December 31, 2025
Year Ended December 31, 2024
% Change
General and administrative expenses, gross
Reimbursed from third parties
Capitalized general and administrative expenses
General and administrative expenses, net
General and administrative expenses, net per Mcfe
The increase in total and per unit general and administrative expenses for the year ended December 31, 2025, compared to the year ended December 31, 2024, was primarily driven by increases in employee compensation and legal expense related to the matters disclosed in Note 18 of our consolidated financial statements.
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Interest Expense (in thousands, except per unit)
Year Ended December 31, 2025
Year Ended December 31, 2024
% Change
Interest on 2026 Senior Notes
Interest on 2029 Senior Notes
Interest on Credit Facility
Amortization of loan costs
Capitalized interest
Other
Total interest expense
Interest expense per Mcfe
Total interest expense for the year ended December 31, 2025, decreased 10% compared to the year ended December 31, 2024. The decrease was primarily due to lower borrowings and a reduced interest rate on our Credit Facility. In the third quarter of 2024, we retired the 2026 Senior Notes and issued the 2029 Senior Notes. Although the interest rate on the 2029 Senior Notes is lower than that of the 2026 Senior Notes, the higher principal balance largely offset the effect of the lower interest rate, resulting in little overall impact on interest expense between periods. We capitalized $6.2 million of interest during the period, compared to $4.8 million in the prior year. See Note 4 of our consolidated financial statements for further details regarding our Credit Facility, issuance of the 2029 Senior Notes and retirement of the 2026 Senior Notes.
Loss on Debt Extinguishment
In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were tendered at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million.
Income Taxes
On July 4, 2025, the OBBBA, which includes a broad range of tax reform provisions, was signed into law in the United States. We completed our assessment of the OBBBA's provision and incorporated the applicable impacts into our current tax expense and deferred tax assets and liabilities. The provisions did not have a significant effect on the Company’s tax positions for the current period.
For the year ended December 31, 2025, our effective tax rate was 21.26% and an income tax expense of $115.5 million. For the year ended December 31, 2024, our effective tax rate was 17.66% and an income tax benefit of $56.1 million. See Note 10 of our consolidated financial statements for further discussion of our income tax expense.
Liquidity and Capital Resources
Overview . We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company’s cash flows. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility. Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
For the year ended December 31, 2025, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, interest payments, dividend payments on our preferred stock and discretionary acreage acquisitions.
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We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.
To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
As of December 31, 2025, we had $1.8 million of cash and cash equivalents compared to $1.5 million as of December 31, 2024, and a net working capital deficit of $115.9 million as of December 31, 2025, compared to net working deficit of $114.2 million as of December 31, 2024. As of December 31, 2025, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2025, was $797.0 million compared to $713.7 million as of December 31, 2024. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
As of February 19, 2026, we had $2.1 million of cash and cash equivalents, $219.0 million borrowings under our Credit Facility, $48.7 million of letters of credit outstanding and $650.0 million of outstanding 2029 Senior Notes.
Debt. In May 2025, we redeemed the remaining $25.7 million principal amount of our 8.00% senior unsecured notes due 2026 at par. As of December 31, 2025, we had $650.0 million of our 6.75% senior unsecured notes due 2029, which is classified as long‑term on our consolidated balance sheet. Based on amounts outstanding at year‑end, anticipated annual cash interest payments on our fixed‑rate debt total approximately $43.9 million. In October 2025, we entered into the Fifth Amendment to our Credit Agreement, which reaffirmed the borrowing base at $1.1 billion and maintained elected commitments at $1.0 billion, with a maturity date of September 12, 2028. As of December 31, 2025, we had $147.0 million of borrowings outstanding, no letters of credit issued, and were in compliance with all financial covenants. At year‑end, we had approximately $804.3 million of availability under the Credit Facility, which remains subject to semi‑annual borrowing base redeterminations based primarily on projected future cash flows, with the next scheduled redetermination occurring in the spring of 2026.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt through privately negotiated transactions, open market repurchases, tender offers or otherwise, but we are under no obligation to do so.
See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt.
Dividends on Preferred Stock . As discussed in Note 5 of our consolidated financial statements, holders of preferred stock were entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). We had the option to pay either cash dividends or PIK Dividends on a quarterly basis. On September 5, 2025, the Company redeemed all of its outstanding preferred stock. During the years ended December 31, 2025 and 2024, the Company paid $1.7 million and $4.2 million, respectively, of cash dividends to holders of our preferred stock. No cash dividends were paid after the Redemption Date.
Supplemental Guarantor Financial Information . The 2029 Senior Notes are guaranteed on a senior unsecured basis by Gulfport and certain of Gulfport’s wholly owned subsidiaries (collectively, the “2029 Senior Notes Guarantors” and, together with the 2026 Senior Notes Guarantors, the “Guarantors”) and certain future subsidiaries of Gulfport that become borrowers or guarantors under any credit agreement with an aggregate principal amount outstanding or commitment amount in excess of $15 million. The 2029 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2029 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors.
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SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.
Derivatives and Hedging Activities . Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.
Subsequent to December 31, 2025 and as of February 19, 2026, we entered into the following natural gas, oil, and NGL derivative contracts:
Period
Type of Derivative Instrument
Index
Daily Volume
Weighted
Average Price
Natural Gas
(MMBtu/d)
($/MMBtu)
Swaps
NYMEX Henry Hub
Swaps
NYMEX Henry Hub
Basis Swaps
TETCO M2
Basis Swaps
Rex Zone 3
Basis Swaps
NGPL TXOK
Oil
(Bbl/d)
($/Bbl)
Costless Collars
NYMEX WTI
Costless Collars
NYMEX WTI
Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2025 (in thousands):
Payment due by period
Contractual Obligations
Total
2031 and Thereafter
Long-term debt (1) :
Principal
Interest
Firm transportation and gathering contracts (2)
Other operational commitments (3)
Operating lease liabilities (4)
Total contractual cash obligations (5)
(1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 4 of our consolidated financial statements for a description of our long-term debt.
(2) See Note 17 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments.
(3) See Note 17 of our consolidated financial statements for a description of our other operational commitments.
(4) See Note 9 of our consolidated financial statements for a description of our operating lease liabilities.
(5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of our consolidated financial statements, respectively.
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Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2025, our material off-balance sheet arrangements and transactions include $48.7 million in letters of credit outstanding against our Credit Facility and $45.3 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase material and services to be used in future drilling and completion activities. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the year ended December 31, 2025, the Company's incurred capital expenditures totaled $526.1 million related to operated activities, of which $428.4 million related to drilling and completion activities, $34.8 million related to maintenance leasehold and land investment and $62.9 million related to discretionary acreage acquisitions.
Our drilling and completion capital expenditures for 2026 are currently estimated to be in the range of $365 million to $390 million. Also, we currently expect to spend approximately $35 million to $40 million in 2026 for maintenance land and seismic investments, primarily focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2026, 2027 and 2028. We expect this capital program to result in approximately 1.030 to 1.055 Bcfe per day of production in 2026.
Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2025, WTI prices ranged from $55.44 to $80.73 per barrel and the Henry Hub spot market price of natural gas ranged from $2.65 to $9.86 per MMBtu. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. If the prices of oil and natural gas continue to be volatile, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.
See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2025.
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Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2025 and 2024 (in thousands):
Year Ended December 31, 2025
Year Ended December 31, 2024
Net cash provided by operating activities
Additions to oil and natural gas properties
Debt activity, net
Debt issuance and loan commitment fees
Repurchases of common stock
Redemption of preferred stock
Net cash payments on performance vesting restricted stock units
Dividends on preferred stock
Shares exchanged for tax withholdings
Other
Net change in cash and cash equivalents
Cash and cash equivalents at end of period
Net cash provided by operating activities. Net cash provided by operating activities was $803.2 million for the year ended December 31, 2025, compared to $650.0 million for the year ended December 31, 2024. The increase was primarily the result of a increase in our natural gas revenues.
Additions to oil and natural gas properties. During the year ended December 31, 2025, we spud 24 gross (23.9 net) operated wells and commenced sales from 30 gross (30.0 net) operated wells targeting the Utica and Marcellus formations for a total cost incurred of approximately $401.0 million. During the year ended December 31, 2025, we did not spud any operated wells and commenced sales from 2 gross (1.8 net) operated wells in the SCOOP for a total incurred cost of approximately $27.5 million. Additionally, the Company incurred $34.8 million related to maintenance leasehold and land investment and $62.9 million related to discretionary acreage acquisitions.
Drilling and completion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the year ended December 31, 2025 and 2024, were as follows (in thousands):
Year Ended December 31, 2025
Year Ended December 31, 2024
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs
Leasehold acquisitions
Other
Total oil and natural gas property expenditures
Debt activity, net. During the year ended December 31, 2025, the Company had $1.4 billion and $1.2 billion in borrowings and repayments, respectively, on its Credit Facility. In May 2025, the Company redeemed the remaining $25.7 million principal amount of its 2026 Senior Notes at par. As of February 19, 2026, the Company had $219.0 million in borrowings outstanding on its Credit Facility.
Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred $14.9 million of debt issuance and loan commitment fees, related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity.
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Repurchases of common stock. During the year ended December 31, 2025, the Company repurchased 1.8 million shares for approximately $336.3 million under the Repurchase Program at a weighted average price of $188.65 per share. For the same period in 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share.
Redemption of preferred stock. On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. During the period between the date of the notice of redemption and the Redemption Date, 28,907 shares of preferred stock were converted into approximately 2.1 million shares of common stock. On the Redemption Date, the Company redeemed the remaining 2,449 shares of preferred stock for cash totaling $31.3 million. Additionally, direct transaction-related costs of $1.1 million were incurred as part of the redemption. See Note 5 of our consolidated financial statements for further discussion of the redemption of preferred stock.
Net cash payments on performance vesting restricted stock units. During the year ended December 31, 2025, the Company settled certain performance vesting restricted stock units awards that were granted in 2022 in cash for $12.3 million, as discussed in Note 7 of our consolidated financial statements.
Dividends on preferred stock. During the year ended December 31, 2025, the Company paid $1.7 million of cash dividends to holders of our preferred stock compared to $4.2 million in the year ended December 31, 2024. No cash dividends were paid after the Redemption Date.
Shares exchanged for tax withholdings. During the year ended December 31, 2025, the Company paid $5.6 million of shares exchanged for tax withholdings compared to $23.6 million in the year ended December 31, 2024. The decrease was primarily due to lower aggregate fair value of vested awards as discussed in Note 7 of our consolidated financial statements.
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Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.
Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.
Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.
Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2025. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. The Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2025 and recognized ceiling test impairments of $373.2 million during 2024. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.
Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information.
Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized.
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Index to Financial Statements
Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.
Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
