GRNT Granite Ridge Resources, Inc. - 10-K

Item 1A. Risk Factors

The following risk factors apply to our business and operations. These risk factors are not exhaustive, and investors are encouraged to perform their own investigation with respect to our business, financial condition and prospects. You should carefully consider the following risk factors in addition to the other information included in this Annual Report, including matters addressed in the section entitled “Cautionary Note Regarding Forward-Looking Statements” and the financial statements and notes to the financial statements included herein. We may face additional risks and uncertainties that are not presently known to us, or that we currently deem immaterial, which may also impair our business or financial condition. The following discussion should be read in conjunction with the financial statements and notes to the financial statements included herein. As used in the risks described in this subsection, references to “we,” “us,” “our” and the “Company” are intended to refer to Granite Ridge and its consolidated subsidiaries, unless the context clearly indicates otherwise.

Risks Related to Our Business and Operations

As a non-operator, our development of successful operations relies extensively on third parties, which could have a material adverse effect on our results of operation.

We have only participated in wells operated by third parties. The success of our business operations depends on the timing of drilling activities and success of our third-party operators. If our operators are not successful in the development, exploitation, production, and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.

Our operators will make decisions in connection with their operations (subject to their contractual and legal obligations to other owners of working interests), which may not be in our best interests. We may have no ability to exercise influence over the operational decisions of our operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on third-party operators could prevent us from realizing target returns for those locations. The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including oil and natural gas prices and other factors generally affecting the industry operating environment; the timing and amount of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of technology; and the rate of production of reserves, if any.

In recent years, we have also made investments in operated partnerships, which comprise of investments in assets that are drilled, developed and operated by private operators. Our operated partnerships are structured such that we retain significant control over acquisition costs and strategy, development costs, timing and rig schedules, and well design. In these partnerships, while we have more influence over development decisions, we still rely on third-party operators for the execution of these decisions. The success of these partnerships is contingent upon the third-party operators’ ability to effectively implement our development plans. Any failure or delay by these operators in executing our development strategies could materially and adversely affect our financial condition and results of operations.

These risks are heightened in a low commodity price environment, which may present significant challenges to our operators. The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital. Commodity prices and/or other conditions have in the past and may in the future cause oil and gas operators to file for bankruptcy. The insolvency of an operator of any of the Properties, the failure of an operator of any of the Properties to adequately perform operations or an operator’s breach of applicable agreements (including failure to spud or place wells into production) could result in penalties, reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety, and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner. Finally, an operator of the Properties may have the right, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, to require us to pay its proportionate share of the defaulting party’s share of costs.

The inability of one or more of our operating partners to meet their obligations to us may adversely affect our financial results.

Our exposures to credit risk, in part, are through receivables resulting from the sale of our oil and natural gas production, which operating partners market on our behalf to energy marketing companies, refineries, and their affiliates. We are subject to credit risk due to the relative concentration of our oil and natural gas receivables with a limited number

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of operating partners. This may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. A low commodity price environment may strain our operating partners, which could heighten this risk. The inability or failure of our operating partners to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our business depends on transportation and processing facilities and other assets that are owned by third parties.

The marketability of our oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, adverse weather events or natural disasters, equipment malfunctions or failures, scheduled or unscheduled maintenance, legal or other reasons, could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells, or the delay or discontinuance of development plans for the Properties. In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we may rely on third-party oil trucking to transport a significant portion of our production to third-party transportation pipelines, rail loading facilities, and other market access points.

In addition, the third parties on whom operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting business on the Properties. Further, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development and increased regulation of pipelines by the Pipeline and Hazardous Materials Safety Administration, and therefore less capacity to transport our products by pipeline. Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce our operating partners’ ability to market oil production and have an adverse effect on us. Operators’ access to transportation options and the prices they receive can also be affected by federal and state regulation — including regulation of oil production, transportation, and pipeline safety — as well as by general economic conditions and changes in supply and demand.

The loss of a key member of the Manager’s management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely, could diminish our ability to conduct our operations and harm our ability to execute our business plan.

We rely on continued contributions of the members of the Manager’s management team by virtue of the MSA. Our success depends heavily upon the continued contributions of those members of the Manager’s management team whose knowledge, relationships with industry participants, leadership, and technical expertise would be difficult to replace. In particular, our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities, and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on the Manager’s management team’s knowledge and expertise in the industry. To continue to develop our business, we rely on the Manager’s management team’s knowledge and expertise in the industry and will use the Manager’s management team’s relationships with industry participants to enter into strategic relationships. The members of the Manager’s management team may terminate their employment with the Manager at any time. If the Manager were to lose key members of its management team, neither the Manager nor we may be able to replace the knowledge or relationships that they possess, and our ability to execute our business plan could be materially harmed. As a result, our operations and financial condition could suffer.

Oil and natural gas prices are volatile. Extended declines in such prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow.

The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Oil and natural gas prices have fluctuated significantly, including periods of rapid and material decline, in recent years. The prices we receive for the oil and natural gas production associated with our working interests heavily influence our production, revenue, cash flows, profitability, reserve bookings and access to capital. Although we seek to mitigate volatility and potential declines in commodity prices through derivative arrangements that hedge a portion of the expected production associated with our working interests, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks.

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The prices we receive for the production and the levels of the production associated with our working interests depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

• changes in global supply and demand for oil and natural gas;

• the actions of OPEC and other major oil producing countries;

• worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics;

• the price and quantity of imports of foreign oil and natural gas;

• political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, particularly those in the Middle East, Russia, South America and Africa;

• the outbreak or escalation of military hostilities, including between Russia and Ukraine, Israel and Hamas, the U.S., Israel and Iran, continued instability in the Middle East, and the potential destabilizing effect such conflicts may pose for the European continent or the global oil and natural gas markets;

• the level of global oil and natural gas exploration, production activity and inventories;

• changes in U.S. energy policy;

• weather conditions and world health events;

• technological advances affecting energy consumption;

• domestic, local and foreign governmental taxes, tariffs and/or regulations;

• proximity and capacity of processing, gathering, storage, oil and natural gas pipelines and other transportation facilities;

• the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and

• the price and availability of alternative fuels.

These factors and the volatility of the energy markets make it extremely difficult to predict oil and natural gas prices. A substantial or extended decline in oil or natural gas prices, such as the significant and rapid decline that occurred in 2020, has resulted in and could result in future impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we may be required to reduce spending or borrow or issue additional equity to cover any such shortfall. Lower oil and natural gas prices may limit our ability to comply with the covenants under any credit facilities (or other debt instruments) and/or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

Our operating partners’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations on our acreage may be curtailed, delayed, or canceled by the operators of the Properties as a result of other factors, including:

• declines in oil or natural gas prices;

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• infrastructure limitations, such as gas gathering and processing constraints;

• the high cost, shortages or delays of equipment, materials and services;

• unexpected operational events, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents;

• title problems;

• pipe or cement failures and casing collapses;

• lost or damaged oilfield development and service tools;

• compliance with environmental, health, safety and other governmental requirements;

• increases in severance taxes;

• regulations, restrictions, moratoria and bans on hydraulic fracturing;

• unusual or unexpected geological formations, and pressure or irregularities in formations;

• loss of drilling fluid circulation;

• environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;

• fires, blowouts, craterings and explosions;

• uncontrollable flows of oil, natural gas or well fluids; and

• pipeline capacity curtailments.

In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells, regulatory penalties and third party claims. We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established or operations are commenced on units containing the acreage or the leases are extended.

A portion of our acreage is not currently held by production or held by operations. Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related Properties. Drilling plans for these areas are generally in the discretion of third-party operators and are subject to change based on various factors that are beyond our control, such as: the availability and cost of capital, equipment, services and personnel; seasonal conditions; regulatory and third-party approvals; oil and natural gas prices; results of title work; gathering system and other transportation constraints; drilling costs and results; and production costs. As of December 31, 2025, we had leases that were not developed that represented 3,922 net acres potentially expiring in 2026, 1,065 net acres potentially expiring in 2027 and 5,524 net acres potentially expiring in 2028 and beyond.

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We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.

An increase in commodity prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies. Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operating partners’ ability to conduct desired or expected operations. In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing commodity prices as producers seek to increase production in order to capitalize on higher commodity prices. In situations where cost inflation exceeds commodity price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash flows.

New technologies may cause the current exploration and drilling methods of our operating partners to become obsolete, and such operators may not be able to keep pace with technological developments in the oil and gas industry.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force our operating partners to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before we or our operating partners can. We cannot be certain that we or our operators will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If our operators are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

Due to previous declines in oil and natural gas prices, we have in the past taken writedowns of the properties that constitute our oil and natural gas properties. We may be required to record further writedowns of our oil and natural gas properties in the future.

In 2025, 2024, and 2023, we were required to write down the carrying value of certain properties that constitute our oil and natural gas properties, and further writedowns could be required by us in the future. Under the successful efforts method of accounting, capitalized costs related to proved oil and natural gas properties, including wells and related support equipment and facilities, are evaluated for impairment on an annual basis, or more frequently if indicators of impairment exist. If undiscounted cash flows are insufficient to recover the net capitalized costs, an impairment charge for the difference between the net capitalized cost of proved properties and their estimated fair values is recognized. A substantial or extended decline in oil or natural gas prices, could result in future impairments of our proved oil and natural gas properties.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty. No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating, exploration and development costs. Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.

We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors, including estimates prepared by our independent reserve engineering firm. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of crude oil and natural gas reserves are inherently imprecise. The process also requires economic assumptions about matters such as oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our estimated reserves relies in part on the ability of the Manager’s reserve engineers to make accurate assumptions. Any significant variance from these assumptions by actual figures could greatly affect our estimated reserves, the economically recoverable quantities of oil

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and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our estimated reserves are based result in the actual quantities of oil and natural gas our operating partners ultimately recover being different from our estimated reserves. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report, subsequent reports we file with the SEC or other Company materials.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

We base the estimated discounted future net cash flows from our proved reserves using specified pricing and cost assumptions. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as the volume, pricing and duration of our oil and natural gas hedging contracts; actual prices we receive for oil and natural gas; our actual operating costs in producing oil and natural gas; the amount and timing of our capital expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our future success depends on our ability to replace reserves that our operators produce.

Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.

We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on the Properties will be productive or that we will recover all or any portion of our investments in the Properties and our reserves.

Extreme weather conditions could adversely affect operators’ ability to conduct drilling activities in some of the areas where the Properties are located.

Drilling and producing activities and other operations in some of our operating areas could be adversely affected by extreme weather conditions, such as floods, lightning, drought, ice and other storms, prolonged freeze events, and tornadoes, which may cause a loss of production from temporary cessation of activity, or lost or damaged facilities and equipment on the part of our operating partners. Such extreme weather conditions could also impact other areas of operations for our operating partners, including access to drilling and production facilities for routine operations, maintenance and repairs and the availability of, and access to, necessary third-party services, such as electrical power, water, gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt operations on the affected Properties and materially increase operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 24% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2025. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves

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will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.

We intend to continue to expand our operations in part through acquisitions. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an inspection is undertaken. Any acquisition involves other potential risks, including, among other things:

• the validity of our assumptions about reserves, future production, revenues and costs;

• a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

• the ultimate value of any contingent consideration agreed to be paid in an acquisition;

• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

• “geological risk,” which refers to the risk that hydrocarbons may not be present or, if present, may not be recoverable economically;

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

• an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.

We may also acquire multiple assets in a single transaction. Portfolio acquisitions via joint-venture or other structures are more complex and expensive than single project acquisitions, and the risk that a multiple-project acquisition will not close may be greater than in a single-project acquisition. An acquisition of a portfolio of projects may result in our ownership of projects in geographically dispersed markets which place additional demands on our ability to manage such operations. A seller may require that a group of projects be purchased as a package, even though one or more of the projects in the portfolio does not meet our investment criteria. In such cases, we may attempt to make a joint bid with another buyer, and such other buyer may default on its obligations.

Further, we may acquire properties subject to known or unknown liabilities and with limited or no recourse to the former owners or operators. As a result, if liability were asserted against us based upon such properties, we may have to pay substantial sums to dispute or remedy the matter, which could adversely affect our cash flow. Unknown liabilities with respect to assets acquired could include, for example: liabilities for clean-up of undiscovered or undisclosed environmental contamination; claims by developers, site owners, vendors or other persons relating to the asset or project site; liabilities incurred in the ordinary course of business; and claims for indemnification by general partners, directors, officers and others indemnified by the former owners of the asset or project sites.

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We may not be able to successfully integrate future acquisitions or realize all of the anticipated benefits from our future acquisitions, and our future results will suffer if we do not effectively manage our expanded operations.

Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. Our future success will depend, in part, upon our ability to manage our expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and basins and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities as a result of increases in the size of our business. There can be no assurances that we will be successful or that we will realize the expected benefits currently anticipated from our acquisitions. In addition, the process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our and the Manager’s management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

Deficiencies of title to our leased interests could significantly affect our financial condition.

Prior to drilling an oil or natural gas well, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination. Any one or more of the foregoing could require us to reverse revenues previously recognized and potentially negatively affect our cash flows and results of operations. While we typically conduct title examination prior to our acquisition of oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, any failure to obtain perfect title to our leaseholds may adversely affect our current production and reserves and our ability in the future to increase production and reserves.

Our derivatives activities could adversely affect our cash flow, results of operations and financial condition.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contracts for a portion of our expected production, which may include swaps, collars, puts and other structures. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and recognize all gains and losses on such instruments in earnings in the period in which they occur. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivatives transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.

Our actual future production may be significantly higher or lower than our estimates at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we may be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which a counterparty to our derivative contracts is unable to satisfy our obligations under the contracts; our production is less than expected; or there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that our operators use for production of oil and natural gas reserves. Abandonment and reclamation of these

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facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our operators' wells but have not established any cash reserve account for these potential costs in respect of any of the Properties. If decommissioning is required before economic depletion of the Properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of the Properties from operational loss-related events. We have insurance policies that include coverage for general liability, operational control of well, oil pollution, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses.

We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance.

We intend to reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. 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. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

We conduct business in a highly competitive industry.

The oil and natural gas industry is highly competitive. The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by our operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.

Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities.

Our competitors also include entities with greater technical, physical and financial resources. Finally, companies and certain private equity firms not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect our business. If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected.

We and our operating partners depend on computer and telecommunications systems and other information and operational technology systems, and failures in those systems or cybersecurity threats, attacks and other disruptions could significantly disrupt our business operations.

We and the Manager have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we and the Manager have developed or may develop proprietary software systems, management techniques and other information and operational technologies incorporating software licensed from third parties. It is possible that we, the Manager, or these third parties, could incur interruptions from cybersecurity attacks, computer viruses or malware, user error, or that third-party service providers

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could cause a breach of our systems or our data. We believe that we and the Manager have positive relations with their information and operational technology vendors; however, any interruptions to our or the Manager’s arrangements with third parties for their computing, communications, or operational infrastructure or any other interruptions to, or breaches of, their information or operational systems could lead to data corruption, communication interruption, corruption or loss of sensitive or confidential information, misdirected wire transfers, and an inability to perform services for our customers; complete or settle transactions; maintain our books and records; prevent environmental damage; and maintain communications or operations; or otherwise significantly disrupt our business operations. Although we and the Manager utilize various procedures and controls designed to monitor these threats and mitigate exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. Furthermore, various third-party resources that we or the Manager rely on, directly or indirectly, in the operation of our business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyberattacks or similar events that are entirely outside the control of us or the Manager, and any such events could significantly disrupt our business operations and/or have a material adverse effect on our results of operations and financial condition. As of the date of this Annual Report, we have not, to our knowledge, experienced any material losses relating to cyberattacks; however, there can be no assurance that we will not suffer material losses in the future.

We are not able to anticipate, detect or prevent all cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until an attack is already underway or significantly thereafter, and because attackers are increasingly using technologies designed to circumvent cybersecurity measures and avoid detection. Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance. Additionally, as cyberattacks become more sophisticated, we may incur significant cost to upgrade or enhance our security measures and procedures to protect against such cyberattacks.

In addition, our operating partners face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of their facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our financial position, results of operations or cash flows. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject our operations to increased risks. Any future terrorist attack at our operating partners’ facilities, or those of their purchasers or vendors, could have a material adverse effect on our financial condition and operations.

We are subject to various laws related to data privacy and cybersecurity. These data laws are not uniform and as the privacy legal landscape develops, we may need to incur additional costs to upgrade or enhance our compliance measures. Any failure or perceived failure by us, the Manager, or our third-party service providers to comply with such data privacy and cybersecurity laws or any unauthorized access or improper disclosure of our data could have a material adverse effect on our financial condition and operations.

A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business, and noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties, injunctive relief, or other liabilities.

A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business. Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties, injunctive relief, or other liabilities.

Additionally, compliance with these laws and regulations may, from time to time, result in increased costs of operations, delay in operations, or decreased production, and may affect acquisition costs. Examples of laws and regulations that govern the environmental aspects of the oil and gas business include the following:

• the CAA, which restricts the emission of air pollutants from many sources, imposes various pre-construction, operating, permitting monitoring, control, recordkeeping, and reporting requirements and is relied upon by the EPA as an authority for adopting climate change regulatory initiatives, including relating to GHG emissions;

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• the CWA, which regulates discharges of pollutants and dredge and fill material to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction as protected waters of the United States;

• the OPA, which requires oil spill prevention, control, and countermeasure planning and imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;

• the SDWA, which protects the quality of the nation’s public drinking water sources through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;

• the CERCLA, which imposes liability without regard to fault on certain categories of potentially responsible parties including generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as on present and certain past owners and operators of sites were hazardous substance releases have occurred or are threatening to occur;

• the RCRA, which imposes requirements for the generation, treatment, storage, transport, disposal and cleanup of non-hazardous and hazardous wastes;

• the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas. Similar protections are afforded to migratory birds under the Migratory Bird Treaty Act (“MBTA”) and bald and golden eagles under the Bald and Golden Eagle Protection Act (“BGEPA”);

• the EPCRA, which requires certain facilities to report toxic chemical uses, inventories, and releases and to disseminate such information to local emergency planning committees and response departments; and

• the OSHA and comparable state statutes, which impose regulations related to the protection of worker health and safety, including requiring employers to implement a hazard communication program and disseminate hazard information to employees.

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict or otherwise regulate the management of hazardous substances and wastes, the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and groundwater, including through permitting requirements, monitoring and reporting requirements, limitations or prohibitions of operations on certain protected areas, requirements to install certain emissions monitoring or control equipment, spill planning and preparedness requirements, and the application of specific worker health and safety criteria (see Item 1. "Business - Governmental Regulation and Environmental Matters" and Item 1. "Business - Climate Change" for further discussion). Failure to comply with applicable environmental laws and regulations by us or third-party operators or contractors could trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements or other corrective measures, and the issuance of orders enjoining existing or future operations. In addition, we or our operating partners may be strictly liable under state or federal laws for environmental damages caused by the previous owners or operators of properties they purchase, without regard to fault.

Environmental laws and regulations change frequently and tend to become more stringent over time, and the implementation of new, or the modification of existing, laws or regulations could adversely affect our business. For example, the regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc that set standards for emission capture and control systems and equipment, leak detection equipment and monitoring, and so-called “green well” completion requirements. Fines and penalties for violations of these rules can be substantial. The rules have been subject to legal challenge, and in February 2025, the D.C. Circuit granted the EPA’s motion to hold the cases in abeyance while the agency reviews the final rules. In March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc, and in November 2025, the EPA issued an interim final rule extending several compliance for certain provisions in the December 2023 rule. Litigation challenging the interim final rule remains pending. We cannot predict when or whether the EPA or the Trump administration may take further action to repeal or modify the final rules, we cannot predict the substance or timing of such changes, if any. However, the requirements of the EPA’s final methane rules have the potential to increase the operating costs of our operators and thus may adversely affect our financial results and cash flows. Moreover, failure to

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comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. These rules could further increase the cost of development and operation of the Properties.

Additionally, some states in which the Properties are located, such as Colorado and New Mexico, have adopted stringent rules and regulations to reduce methane emissions and emissions of other hydrocarbons, VOCs, and nitrogen oxides associated with oil and gas facilities. For example, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) have adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, the development of pre-production air monitoring plans at certain oil and gas facilities, enclosed combustion device testing, a methane intensity reduction requirement based on statewide volume of production and additional measures for reducing and eliminating emissions from pneumatic devices. AQCC is expected to undertake several additional rulemaking efforts to further reduce emissions over the next several years, and in February 2026, adopted regulations to reduce methane emissions from oil and gas operations in line with the federal Subparts OOOOb and OOOOc. Additionally, the Colorado Energy and Carbon Management Commission in October 2024 finalized rules that consider the cumulative impacts of air emissions from oil and gas projects in permitting decisions. State rules and regulations such as these could significantly increase the costs to develop and operate the Properties, result in a delay in operations or decreased production, and may affect acquisition costs.

We anticipate that hydraulic fracturing will be engaged in by some or all opportunities in which we invest, which could be adversely affected by regulatory initiatives related to hydraulic fracturing.

Hydraulic fracturing is an important and commonly used process that we anticipate will be engaged in by some or all opportunities in which it invests. Hydraulic fracturing is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.

The EPA has asserted authority over certain hydraulic-fracturing activities that use diesel fuel under the SDWA. In addition, legislation such as the Fracturing Responsibility and Awareness of Chemicals Act and similar proposals have been repeatedly introduced before Congress to provide for federal regulation of hydraulic fracturing, such as through disclosure requirements for chemical additives used in hydraulic fracturing fluids. Certain states (including states in which the Properties are located) have adopted, and other states are considering adopting, regulations that could impose more stringent permitting and well construction requirements on hydraulic-fracturing operations or seek to ban fracturing activities altogether. For example, Colorado Senate Bill 19-181 amended state law to give municipalities and counties greater local control over siting and permitting of oil and gas facilities, and some municipalities within the state have implemented regulations within their jurisdictions. In the event federal, tribal, state, local, or municipal legal restrictions are adopted in our target areas, the investments may incur significant additional compliance costs, experience delays in exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. A number of governmental bodies, including the EPA, a committee of the U.S. House of Representatives, the U.S. Department of Energy, and a number of other federal agencies have from time to time analyzed, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. As these studies proceed, and depending on their scope and results, they could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory programs. This, in turn, could lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing, which could adversely affect the investments.

Seismicity concerns associated with injection of produced water and certain other field fluids into disposal wells has led to increased regulation of saltwater injection and disposal wells in certain areas of states in which the Properties are located, which could increase the cost of, or limit the number of facilities available for, disposal of produced water from oil and gas exploration and production operations at the Properties.

Flowback and produced water or certain other field fluids gathered from oil and natural gas exploration and production operations are often injected or disposed of in underground disposal wells. This disposal process has been linked to increased induced seismicity events in certain areas of the country. Certain states (including states in which the Properties are located) have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or in underground disposal wells, and state agencies implementing these requirements may issue orders directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, the Colorado Oil and Gas Conservation Commission adopted regulations in November 2020 that impose various new requirements on the underground injection of fluid wastes to further seismic safety and protection of the environment. In recent years, the RRC has also imposed prohibitions and restrictions on SWD wells in response to a number of earthquakes in the Midland Basin.

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Most recently, in May 2025, the RRC released updated guidance for disposal well permits in the Permian Basin that placed new limits on maximum injection pressure and volumes to ensure safety. Such restrictions and requirements could limit oil and gas well exploration and production activities underlying the investments or increase the cost of those activities if wastewater disposal options become limited (see Item 1. "Business - Governmental Regulation and Environmental Matters - Environmental Matters" for further discussion).

Specific climate legislation and regulation regarding emissions of carbon dioxide, methane, and other greenhouse gases may develop or be enacted, which could adversely affect the oil and gas industry and demand for the oil and gas produced from the Properties.

The energy industry is affected from time to time in varying degrees by political developments and a wide range of federal, tribal, state and local statutes, rules, orders and regulations that may, in turn, affect the operations and costs of the companies engaged in the energy industry. Notwithstanding the EPA’s final rule in February 2026 revoking the GHG “Endangerment Finding” that provides the basis for its authority to regulate GHG emissions, the EPA under previous administrations has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. Litigation has already been filed challenging the February 2026 rule, and while we cannot predict the final outcome, as a result, there is significant uncertainty with respect to regulation of GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on the Properties. Further, the IRA, which the U.S. Congress passed in August 2022, includes a charge for excess methane emissions from certain oil and gas facilities, though the EPA’s rule implementing the charge was revoked in March 2025 following a Joint Resolution of Disapproval under the Congressional Review Act, and the One Big Beautiful Bill Act, passed in July 2025, delayed implementation of the charge until 2034.

In the absence of comprehensive federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact us, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from the Properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas, that may be imposed in various states, as well as state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets. Finally, it should be noted that climate changes may have significant physical effects, such as increased frequency and severity of storms, freezes, floods, drought, hurricanes and other climatic events; if any of these effects were to occur, they could have an adverse effect on us.

In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces demand for corporate transparency and a demonstrated commitment to sustainability goals. ESG programs and goals, which are often aspirational, and which may include voluntary targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing, and sometimes conflicting, focus of certain investors and stakeholders, and companies that are perceived to be ESG laggards or are without robust ESG programs may find access to capital and investors more challenging in the future. Further, while reporting on most ESG information is, generally, currently voluntary, in March 2024, the SEC finalized rules establishing a framework for the reporting of climate risks, targets, and metrics. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges, with such litigation held in abeyance until the SEC repeals, reconsiders, or otherwise modifies the rule. In March 2025, the SEC voted to end its defense of the rule, though to date no further action has been taken to repeal the rule.

Fuel and energy conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.

Fuel and energy conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased

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competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.

Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas exploration and production and related infrastructure projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will continue to rise in the future, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.

The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Increased attention to ESG matters may impact our business.

Increased attention to climate change, fuel conservation measures, alternative fuel requirements, incentives to conserve energy or use alternative energy sources, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increased attention to climate change and any related negative public perception regarding us and/or our industry, for example, may result in demand shifts for our products, increased litigation risk for us, and increased, and sometimes conflicting, regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state, local, tribal and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.

In addition, certain organizations that provide information, ratings or proxy advisory services to investors on corporate governance and related matters have developed processes for evaluating companies on their approach to ESG matters. Such ratings or recommendations are used by some investors to inform their investment and voting decisions. Although this trend has waned recently, to the extent unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets leads to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, such ratings could have a negative impact on our access to and costs of capital or the ability to complete projects. Certain financial institutions may also, of their own accord, elect not to provide or place additional restrictions on funding or insurance for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

We rely on the Manager for various certain key services under the MSA, which could result in conflicts of interest and other unforeseen risks.

Under the MSA with the Manager, our success depends upon the Manager who will have overall supervision and control certain business affairs of us and our investment activities. Further, the employees of the Manager and its respective principals and managers (as applicable) will devote a portion of their time to the affairs of our business for the proper performance of their duties. However, other investment activities of the Manager are likely to require those individuals to devote substantial amounts of their time to matters unrelated to our business. Pursuant to the MSA, we will be offered the opportunity to participate in certain of these activities.

The MSA provides for the Manager to offer us the opportunity to participate in certain investments made by funds affiliated with the Manager and for us to offer such funds the opportunity to participate in certain investments made by us. The Manager may make investments on behalf of its funds that are not a part of our Company or in which such funds may co-invest with us, any such transactions may involve conflicts of interest among us, the Manager, and their affiliates, some or all of which may not be thought of or taken into account in reviewing and approving such transactions. In certain events, the Manager may not be in a position unilaterally to control such investments or exercise certain rights associated with such investments. We may be subject to conflicts of interest involving the Manager and its affiliates, and the Manager may enter into relationships with developers, co-owners or other affiliates, some of which may give rise to conflicts of interest. To the

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extent not addressed by the MSA, we and the Manager have implemented policies as necessary or appropriate to deal with such potential conflicts.

Investment analyses and decisions by the Manager may frequently be required to be undertaken on an expedited basis to take advantage of investment opportunities. In such cases, the information available at the time of making an investment decision may be limited, and the Manager may not have access to complete information regarding the investment. Therefore, no assurance can be given that the Manager will have knowledge of all circumstances that may adversely affect an investment. In addition, the Manager expects to rely upon specialized expert input by various third-party consultants and service providers in connection with its evaluation of proposed investments.

Additionally, if the MSA is terminated or not renewed upon the end of its term, it may be difficult for us to hire the necessary personnel in a timely manner to handle the matters and services being provided by the Manager, which could have a material adverse effect on our business and results of operations.

We rely to a large degree on the Manager to maintain an effective system of internal control over financial reporting and we may not be able to accurately report our financial results or prevent fraud.

Under the terms of the MSA, we must rely to a large extent on the internal controls and financial reporting controls of the Manager, and the Manager’s failure to maintain effective controls or comply with applicable standards may adversely affect us. On March 3, 2023, the Audit Committee of our Board of Directors concluded that our previously issued unaudited condensed combined financial statements as of and for the three and nine month periods ended September 30, 2022, included in the Company’s Quarterly Report on Form 10-Q filed on November 14, 2022 were materially misstated. In addition, the Company did not have effective controls over Information Technology General Controls pertaining to user access management. In connection with the material misstatement and lack of effective user access controls, our Company’s management identified material weaknesses in our disclosure controls and internal control over financial reporting.

In addition, any failure of the Manager to remediate any identified material weakness, or any future failure of the Manager to maintain adequate internal controls over financial reporting or to implement required, new or improved controls, or difficulties encountered in their implementation, could cause additional material weaknesses or significant deficiencies in our financial reporting and could result in errors or misstatements in our consolidated financial statements that could be material. Any third-party failure to achieve and maintain effective internal controls could have a material adverse effect on our business, our ability to access capital markets and investors’ perception of us. Additionally, if we or our independent registered public accounting firm were to conclude that third-party internal controls over financial reporting were not effective, any material weaknesses in such internal controls could require significant expense and management time to remediate.

The borrowing base under our Credit Agreement may be reduced in light of commodity price declines, which could limit us in the future.

At the closing of the Business Combination, we entered into a Credit Agreement, secured by a first priority mortgage and security interest in substantially all of our assets and our restricted subsidiaries. Availability under the Credit Agreement is limited to the aggregate commitments of the lenders, which is the least of the aggregate maximum credit amounts of the lenders, the borrowing base and the elected commitment amount chosen by us and, in the case of an elected commitment increase, consented to by the increasing lender(s). Our borrowing base under the Credit Agreement will depend on, among other things, the value of the proved reserves attributed to, and projected revenues from, the oil and natural gas properties securing our Credit Agreement, many of which factors are beyond our control. Accordingly, lower commodity volumes and prices may reduce the available amount of our borrowing base under the Credit Agreement. Our borrowing base is determined at the discretion of the lenders party to the Credit Agreement and is subject to semi-annual redeterminations, as well as any special redeterminations described in the Credit Agreement. We may reset the elected commitment amount under the Credit Agreement in conjunction with each borrowing base redetermination. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, we would be required to repay the excess or otherwise remedy the deficiency in accordance with the terms of the Credit Agreement. We may not have sufficient funds to make such repayments, and may not have access to the equity or debt capital markets, at the time such repayment obligations are due. If we do not have sufficient funds and are otherwise unable to raise sufficient funds, negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results. Please see the section

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entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources — Granite Ridge Credit Agreement” for more information.

Risks Relating to Ownership of Our Common Stock

Sales of our common stock by our securityholders (or the perception that such shares may be sold) or issuances by us may cause the market price of our securities to drop significantly, even if our business is doing well.

The sale of shares of our common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that it deems appropriate.

In addition, the shares of our common stock reserved for future issuance under the Granite Ridge 2022 Omnibus Incentive Plan (the “Incentive Plan”) will become eligible for sale in the public market once those shares are issued, subject to provisions relating to various vesting requirements and, in some cases, limitations on volume and manner of sale applicable to affiliates under Rule 144. The maximum number of shares of our common stock reserved for issuance to directors, officers, employees and consultants or advisors employed by or providing service to the Company under our equity incentive plans is 6.5 million, which represented approximately 4.9% of the shares of our common stock outstanding following the consummation of the Business Combination. As of December 31, 2025, the Company had 3.8 million shares of common stock remaining available for future awards under the Incentive Plan. We have filed a registration statement on Form S-8 under the Securities Act of 1933, as amended (the "Securities Act") to register shares of our common stock or securities convertible into or exchangeable for shares of our common stock issued pursuant to the Incentive Plan. Accordingly, shares registered under such registration statements are available for sale in the open market.

In the future, we may also issue securities in connection with investments or acquisitions. The amount of shares of our common stock issued in connection with an investment or acquisition could constitute a material portion of our then-outstanding shares of common stock. Any issuance of additional securities in connection with investments or acquisitions may result in additional dilution to our stockholders and may have an adverse effect on the price of shares of our common stock.

Future issuances of debt securities and/or equity securities may adversely affect us, including the market price of our common stock, and may be dilutive to our existing stockholders.

In the future, we may incur debt and/or issue equity ranking senior to our common stock. Those securities will generally have priority upon liquidation. Such securities also may be governed by an indenture or other instrument containing covenants restricting our operating flexibility. Additionally, any convertible or exchangeable securities that we issue in the future may have rights, preferences and privileges more favorable than those of our common stock. Because our decision to issue debt and/or equity in the future will depend, in part, on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or success of our future capital raising efforts. As a result, future capital raising efforts may reduce the market price of our common stock and be dilutive to our existing stockholders.

Anti-takeover provisions in our organizational documents could delay or prevent a change of control.

Certain provisions of our amended and restated certificate of incorporation and our amended and restated bylaws may have an anti- takeover effect and may delay, defer or prevent a merger, acquisition, tender offer, takeover attempt or other change of control transaction that a stockholder might consider in their best interest, including those attempts that might result in a premium over the market price for the shares held by our stockholders. These provisions, among other things:

• establish a staggered board of directors divided into three classes serving staggered three-year terms, such that not all members of our Board will be elected at one time;

• authorize our Board to issue new series of preferred stock without stockholder approval and create, subject to applicable law, a series of preferred stock with preferential rights to dividends or our assets upon liquidation, or with superior voting rights to existing common stock;

• eliminate the ability of stockholders to call special meetings of stockholders;

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• eliminate the ability of stockholders to fill vacancies on our Board;

• establish advance notice requirements for nominations for election to our Board or for proposing matters that can be acted upon by stockholders at annual stockholder meetings;

• permit our Board to establish the number of directors;

• provide that our Board is expressly authorized to make, alter or repeal our amended and restated bylaws;

• provide that stockholders can remove directors only for cause; and

• limit the jurisdictions in which certain stockholder litigation may be brought.

These anti-takeover provisions could make it more difficult for a third-party to acquire us, even if the third party’s offer may be considered beneficial by many of our stockholders. As a result, our stockholders may be limited in their ability to obtain a premium for their shares. These provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire.

Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities.

Our amended and restated certificate of incorporation provides that we, to the fullest extent provided by law, renounce any expectancy that our directors or officers will offer to us any corporate opportunity to which it becomes aware, except to the extent such corporate opportunity was offered to such person solely in his or her capacity as a director or officer of ours. Officers and directors, including those nominated by the funds managed by Grey Rock or its affiliates, may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to affiliates (subject to the MSA that sets forth an allocation of certain acquisition opportunities between us and funds associated with the Manager) or other businesses in which they have invested or are otherwise associated, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Grey Rock and its affiliates, may dispose of properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing of our interest and expectancy in any business opportunity that may be from time to time presented our officers and directors, could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for us. We cannot assure you that any conflicts that may arise between us and any of such parties, on the other hand, will be resolved in our favor. As a result, competition from Grey Rock and its affiliates or businesses associated with our other officers and directors could adversely impact our results of operations.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, 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 that, unless we consent in writing to the selection of an alternative forum, that the Court of Chancery shall, to the fullest extent permitted by law, be the sole and exclusive forum for any stockholder (including a beneficial owner) to bring any derivative action on our behalf, any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of ours, any action asserting a claim against us, our directors, officers or employees arising pursuant to any provision of the DGCL or our amended and restated certificate of incorporation or our amended and restated bylaws, or any action asserting a claim against us, our directors, officers or employees governed by the internal affairs doctrine, in each case subject to the Court of Chancery having personal jurisdiction over any indispensable parties (or such parties consent to the personal jurisdiction of the Court of Chancery within ten days following the Court of Chancery’s determination as to such personal jurisdiction) and subject matter jurisdiction over the claim. The foregoing forum selection provision shall not apply to claims arising under the Exchange Act, the Securities Act, or any other claim for which the federal courts have exclusive jurisdiction.

In addition, our amended and restated certificate of incorporation provides that the federal district courts of the United States will be the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act;

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however, there is uncertainty as to whether a court would enforce such provision. Although we believe these provisions benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against us or our directors and officers.

Alternatively, if a court were to find the choice of forum provision contained in our amended and restated 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 harm our business, financial condition, and operating results. For example, under the Securities Act, state and federal courts have concurrent jurisdiction over all suits brought to enforce any duty or liability created by the Securities Act, and investors cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring any interest in our common stock shall be deemed to have notice of and consented to this exclusive forum provision, but will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder.

We are a “controlled company” under the corporate governance rules of the NYSE and, as a result, qualify for exemptions from certain corporate governance requirements. We rely on certain of these exemptions, which means you will not have the same protections afforded to stockholders of companies that are subject to such requirements.

Grey Rock Energy Partners GP III, L.P. ("Grey Rock Fund III"), pursuant to a Voting Agreement, dated as of August 25, 2023, by and among Grey Rock Fund III, Grey Rock Energy Partners GP II, L.P., and the other stockholders party thereto, controls a majority of our voting common stock. As a result, we are a “controlled company” within the meaning of the corporate governance standards of the rules of the NYSE. Under these rules, a listed company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements, including:

• the requirement that a majority of our Board of Directors consist of independent directors;

• the requirement that our director nominations be made, or recommended to the full Board of Directors, by our independent directors or by a nominations committee that is comprised entirely of independent directors and that we adopt a written charter or board resolution addressing the nominations process; and

• the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

As long as we remain a “controlled company,” we may elect to take advantage of any of these exemptions. Our Board of Directors does not have a majority of independent directors, our compensation committee does not consist entirely of independent directors and does not have a nominating committee. Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the rules of the NYSE.

Changes in applicable tax laws or interpretations thereof or the imposition of new or increased taxes or fees may increase our future tax liabilities and adversely affect our operating results and cash flows.

We are subject to various complex and evolving U.S. federal, state and local tax laws. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us (in each case, possibly with retroactive effect). For example, the IRA resulted in fundamental changes to the U.S. Internal Revenue Code, as amended, including, among many other things, a 15% corporate alternative minimum tax on certain large corporations, a nondeductible 1% excise tax on the value of certain stock that a company repurchases, and various tax incentives for energy and climate initiatives. In addition, from time to time, U.S. federal and state level legislation has been proposed that that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently applicable to natural gas and oil exploration and development companies. Such proposed legislative changes include, but are not limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Further, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction. The passage of any legislation as a result of these proposals and

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other changes in tax laws or the imposition of new or increased taxes or fees could increase our future tax liabilities and adversely affect our operating results and cash flows.

In addition, our effective tax rate and tax liability are based on the application of current income tax laws, regulations and treaties. These laws, regulations and treaties are complex and often open to interpretation. In the future, the tax authorities could challenge our interpretation of laws, regulations and treaties, resulting in additional tax liability or adjustment to our income tax provision that could increase our effective tax rate which could adversely affect our operating results and cash flows. Changes to tax laws may also adversely affect our ability to attract and retain key personnel.

The payment of dividends is at the discretion of our Board of Directors, and we cannot assure you that we will continue making dividend payments in the future.

We paid dividends of $57.7 million, or $0.44 per share, and $57.5 million, or $0.44 per share during the years ended December 31, 2025 and 2024, respectively. However, our Board of Directors is not obligated to make any future dividend payments. Instead, the declaration and payment of dividends are at the discretion of our Board of Directors and depend on a number of factors, including applicable law, economic conditions, financial condition, results of operations, projections, liquidity, earnings, legal requirements, restrictions in the Credit Agreement, and other factors our Board of Directors deems relevant. There can be no assurance that dividends will be declared in the future, or if declared, that the amount will be consistent with historical levels.

General Risks

The market price of shares of our common stock may be volatile.

Fluctuations in the price of our securities could contribute to the loss of all or part of your investment. The trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Price volatility may be greater if the public float and trading volume of our common stock is low.

Any of the factors listed below could have a material adverse effect on your investment. Our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline. Factors affecting the trading price of our securities may include:

• actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;

• changes in the market’s expectations about our operating results;

• lack of adjacent competitors;

• our operating results failing to meet the expectation of securities analysts or investors in a particular period;

• changes in financial estimates and recommendations by securities analysts concerning us or the industries in which we operate in general;

• operating and stock price performance of other companies that investors deem comparable to us;

• announcements by us or our competitors of significant contracts, acquisitions, joint ventures, other strategic relationships or capital commitments;

• changes in laws and regulations affecting our business;

• commencement of, or involvement in, litigation involving us;

• changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;

• the volume of shares of our common stock available for public sale;

• any significant change in our Board of Directors or management;

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• speculation by the press or investment community;

• sales of substantial amounts of our common stock by our directors, executive officers or significant stockholders or the perception that such sales could occur;

• general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations and acts of war or terrorism; and

• changes in accounting standards, policies, guidelines, interpretations or principles.

Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and the NYSE have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected.

The ongoing military conflicts between Ukraine and Russia, Israel and Hamas, the joint U.S.-Israel strikes on Iran, and continued instability in the Middle East has caused unstable market and economic conditions and is expected to have additional global consequences, such as heightened risks of cyberattacks. Our business, financial condition, and results of operations may be materially adversely affected by the negative global and economic impact resulting from these conflicts or any other geopolitical tensions.

Worldwide economic, political and military events, including war, terrorist activity, and events in the Middle East, have contributed, and are likely to continue to contribute, to oil and natural gas price volatility. For example, the ongoing armed conflicts between Russia and Ukraine, Israel and Hamas, the U.S., Israel and Iran and the continuation of, and the escalation in the severity of, these conflicts has led to extreme regional instability, caused dramatic fluctuations in global financial markets and has increased the level of global economic uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has caused increased volatility in commodity prices. Further, the Houthi movement, which controls parts of Yemen, has targeted and launched numerous attacks on Israeli, American and international commercial marine vessels in the Red Sea as the ships approach the Suez Canal, resulting in many shipping companies re-routing to avoid the region altogether and worsening existing supply chain issues, including delays in supplier deliveries, extended lead times and increased cost of freight, impacts to the shipping of oil and gas, insurance and materials. The joint U.S.-Israel military strikes on Iran have heightened the potential for further conflict with Iran, a major oil producer. Continued hostilities involving the Houthi movement in Yemen and the Hezbollah movement in Lebanon have further contributed to instability in the region.

In addition, the United States and other countries have imposed sanctions on Russia which increases the risk that Russia, as a retaliatory action, may launch cyberattacks against the United States, its government, infrastructure and businesses.

The extent and duration of the military action, sanctions and resulting market disruptions are impossible to predict, but could be substantial. Prolonged unfavorable economic conditions or uncertainty as a result of the military conflict in the Middle East may adversely affect our business, financial condition, and results of operations. Any of the foregoing may also magnify the impact of other risks described in this Annual Report.

World health events may materially adversely affect our business.

World health events may cause disruptions to our business and operational plans, which may include (i) shortages of employees or partners, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, and (v) restrictions that we and our partners impose, including facility shutdowns, to ensure the safety of employees and others. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.

Further, the effects of a world health event could negatively impact global demand for crude oil and natural gas, which may contribute to volatility that could impact the price we and our partners receive for oil and natural gas and materially and adversely affect the demand for and marketability of production, as well as lead to temporary curtailment or shut-ins of production due to lack of downstream demand or storage capacity. Additionally, to the extent a pandemic, epidemic or outbreak of an infectious disease adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in this Item 1A. “Risk Factors.”

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Adverse developments affecting the financial services industry, such as actual events or concerns involving liquidity, defaults or non-performance by financial institutions or transactional counterparties, could adversely affect our current and projected business operations and financial condition and results of operations.

Events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. Most recently, on March 10, 2023, Silicon Valley Bank (“SVB”) was closed by the California Department of Financial Protection and Innovation, which appointed the Federal Deposit Insurance Corporation (“FDIC”) as receiver. Similarly, on March 12, 2023, Signature Bank and Silvergate Capital Corp. were each swept into receivership. Borrowers under credit agreements, letters of credit and certain other financial instruments with any financial institution that is placed into receivership by the FDIC may be unable to access undrawn amounts thereunder. Access to funding sources and other credit arrangements could be significantly impaired by factors that affect the financial services industry or economy in general. These factors could include, among others, events such as liquidity constraints or failures, the ability to perform obligations under various types of financial, credit or liquidity agreements or arrangements, disruptions or instability in the financial services industry or financial markets, or concerns or negative expectations about the prospects for companies in the financial services industry.

In addition, investor concerns regarding the U.S. or international financial systems could result in less favorable commercial financing terms, including higher interest rates or costs and tighter financial and operating covenants, or systemic limitations on access to credit and liquidity sources, thereby making it more difficult to acquire financing on acceptable terms or at all. Any decline in available funding or access to our cash and liquidity resources could, among other risks, adversely impact our ability to meet our financial or other obligations. Any of these impacts, or any other impacts resulting from the factors described above or other related or similar factors, could have material adverse impacts on our liquidity and our business, financial condition or results of operations.

Our operations and financial performance may be negatively affected directly or indirectly by changes in trade policies

and tariffs.

In recent years, the United States increased tariffs for certain goods, which triggered other nations to also increase tariffs on certain of their goods. The Trump administration has made many announcements regarding tariffs and the extent and, although the Supreme Court recently ruled that certain reciprocal tariffs are unconstitutional, the duration of other existing tariffs or the imposition of new tariffs remain uncertain. If maintained or implemented, tariffs and the potential escalation of trade disputes could pose a risk to our business and also directly impact our operating expenses. For example, previously announced 25% tariffs on imported steel are likely to lead to increased material costs.

Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included elsewhere in this Annual Report on Form 10-K.

The following discussion contains “ forward ‑ looking statements ” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward ‑ looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report. Please read “Cautionary Note Regarding Forward ‑ Looking Statements.” Also, please read the risk factors and other cautionary statements described under “ Part I, Item 1A. Risk Factors. ” We assume no obligation to update any of these forward ‑ looking statements, except as required by applicable law.

Overview

Granite Ridge is a scaled energy company which aims to provide shareholders with exposure similar to energy private equity through operated partnerships and traditional non-operated assets. We own assets in six prolific unconventional basins across the United States. We aim to deliver a diversified portfolio with best-in-class full cycle returns by investing in a large number of high-graded opportunities developed by proven public and private operators. We focus on success as measured by total shareholder returns, which we seek to balance with a low leverage profile.

As of December 31, 2025, we owned an interest in 3,602 gross (245 net) producing wells, 355,252 gross (47,534 net) developed acres, and 33,399 gross (12,504 net) undeveloped acres, all located in the United States.

Our average daily production for the year ended December 31, 2025 was 31,984 Boe per day.

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Business Combination

On October 24, 2022 (the “Closing Date”), Granite Ridge and Executive Network Partnering Corporation ("ENPC") consummated the business combination pursuant to the terms of the Business Combination Agreement, dated as of May 16, 2022 (the “Business Combination Agreement”), by and among ENPC, Granite Ridge, ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub”), and Granite Ridge Holdings, LLC, a Delaware limited liability company formerly known as GREP Holdings, LLC (“GREP”).

Pursuant to the Business Combination Agreement, on the Closing Date, (i) ENPC Merger Sub merged with and into ENPC (the “ENPC Merger”), with ENPC surviving the ENPC Merger as a wholly-owned subsidiary of Granite Ridge and (ii) GREP Merger Sub merged with and into GREP (the “GREP Merger,” and together with the ENPC Merger, the “Mergers”), with GREP surviving the GREP Merger as a wholly-owned subsidiary of Granite Ridge (the transactions contemplated by the foregoing clauses (i) and (ii) the “Business Combination,” and together with the other transactions contemplated by the Business Combination Agreement, the “Transactions”).

For additional information on the Business Combination See Note 1 in the Notes to the Consolidated Financial Statements.

Source of Our Revenues

We derive our revenues from our interests in the sale of oil and natural gas production. Revenues are a function of production, the prevailing market price at the time of sale, oil quality, and transportation costs to market. We use derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

Lease operating expenses

Lease operating expenses are the costs incurred in the operation of producing properties, including workover costs. Expenses for field employees’ salaries, saltwater disposal, repairs and maintenance comprise the most significant portion of our lease operating expenses. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. A portion of our operating cost components are variable and change in correlation to production levels.

Production and ad valorem taxes

Production taxes are paid on produced oil and natural gas. Ad valorem taxes are paid on the value of our properties in certain states. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

Depletion and accretion expense

Depletion and accretion include the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and successful development efforts and allocate these costs to each unit of production using the units of production method. Accretion expense relates to the passage of time of our asset retirement obligations.

Impairment expense

We evaluate capitalized costs related to proved and unproved oil and natural gas properties, including wells and related oil sales support equipment and facilities, for recoverability when indicators of impairment exist. If undiscounted cash flows are insufficient to recover the net capitalized costs of proved properties, we recognize an impairment charge for the difference between the net capitalized cost of proved properties and their estimated fair values. Unproved oil and natural

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gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects.

General and administrative expenses

General and administrative expenses include overhead, including payroll and benefits for our corporate staff, management and annual service fees under the MSA, audit and other professional fees and legal compliance.

Interest expense

We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

Gain (loss) on derivative contracts

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and natural gas. Gain (loss) on derivative contracts is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

• the timing and success of drilling and production activities by our operating partners;

• the prices and the supply and demand for oil and natural gas;

• the quantity of oil and natural gas production from the wells in which we participate;

• changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil and natural gas;

• our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and

• the level of our operating expenses.

In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage in the Eagle Ford, Permian, Bakken, Haynesville, Denver-Julesburg and Appalachian Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.

The price of oil and natural gas can vary depending on the market in which it is sold and the means of transportation used to transport the oil and natural gas to market.

The price at which our oil and natural gas production is sold typically reflects either a premium or discount to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil and natural gas price differentials between the applicable benchmark and the sales prices we receive for our oil and natural gas production.

Our oil price differential to the NYMEX benchmark price during 2025, 2024 and 2023 was $(3.76) per barrel, $(3.57) per barrel and $(1.40) per barrel, respectively. Our natural gas price differential during 2025, 2024 and 2023 was $(0.96) per Mcf, $(0.31) per Mcf and $0.19 per Mcf, respectively.

Market Conditions

The price that we receive for the oil and natural gas our operators produce is largely a function of market supply and demand. Because our oil and natural gas revenues are heavily weighted toward oil, we are more significantly impacted by

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changes in oil prices than by changes in the price of natural gas. Worldwide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices.

Historically, commodity prices have been volatile, and we expect the volatility to continue in the future.

Although we cannot predict the occurrence of events that may affect future commodity prices, or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business.

Prices for various quantities of natural gas and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2025, 2024 and 2023.

December 31,

Average NYMEX Prices (1)

Oil (per Bbl)

Natural gas (per Mcf)

(1) Based on average NYMEX closing prices.

Results of Operations

The following tables and related discussion set forth key operating and financial data as of and for the years ended December 31, 2025 and 2024. For similar operating and financial data and discussion of our 2024 results compared to our 2023 results, refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Part II of our annual report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on March 6, 2025. Because of normal production declines, increased or decreased drilling activities, fluctuations in

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commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.

Year Ended December 31,

Net Sales (in thousands):

Oil sales

Natural gas and related product sales

Revenues

Net Production:

Oil (MBbl)

Natural gas (MMcf)

Total (MBoe) (1)

Average Daily Production:

Oil (Bbl)

Natural gas (Mcf)

Total (Boe) (1)

Average Sales Prices:

Oil (per Bbl)

Effect of gain on settled oil derivatives on average price (per Bbl)

Oil net of settled oil derivatives (per Bbl) (2)

Natural gas and related product sales (per Mcf)

Effect of gain on settled natural gas derivatives on average price (per Mcf)

Natural gas and related product sales net of settled natural gas derivatives (per Mcf) (2)

Realized price on a Boe basis excluding settled commodity derivatives

Effect of gain on settled commodity derivatives on average price (per Boe)

Realized price on a Boe basis including settled commodity derivatives (2)

Operating Expenses (in thousands):

Lease operating expenses

Production and ad valorem taxes

Depletion and accretion expense

Impairments of long-lived assets

General and administrative

Costs and Expenses (per Boe):

Lease operating expenses

Production and ad valorem taxes

Depletion and accretion

Impairments of long-lived assets

General and administrative

Net Producing Wells at Period-End:

(1) Natural gas is converted to Boe using the ratio of one barrel of oil to six Mcf of natural gas.

(2) The presentation of realized prices including settled commodity derivatives is a result of including the net cash receipts from (payments on) commodity derivatives that are presented in our consolidated statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.

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Oil, Natural Gas and Related Product Sales

Our revenues vary from year to year primarily due to changes in realized commodity prices and production volumes. Our oil and natural gas sales for the year ended December 31, 2025 increased 18% from the year ended December 31, 2024. Oil revenues for the year ended December 31, 2025 increased by 10% compared to the same period in 2024, driven by an 31% increase in production, partially offset by a 16% decrease in realized prices, excluding the effect of settled derivatives. Natural gas revenues increased by 70% for the year ended December 31, 2025 compared to 2024, driven by a 36% increase in realized natural gas prices, excluding the effect of settled commodity derivatives, and a 25% increase in production.

Production from oil and gas properties increased because of drilling success and the acquisition of additional net revenue interests. This increase in total production is offset by the natural decline of the production rate of existing oil and natural gas wells. The number of wells we participated in increased from 202.40 net wells in 2024 to 244.74 net wells in 2025.

The following table sets forth information regarding our oil and natural gas production by basin.

Year Ended December 31,

Net Production:

Oil (MBbl)

Permian

Eagle Ford

Bakken

Haynesville

Appalachian

Total

Natural Gas (MMcf)

Permian

Eagle Ford

Bakken

Haynesville

Appalachian

Total

Total (MBoe)

Permian

Eagle Ford

Bakken

Haynesville

Appalachian

Total

Lease Operating Expenses

Lease operating expenses were $84.9 million ($7.27 per Boe) for the year ended December 31, 2025, a increase of 48% from $57.5 million ($6.29 per Boe) for 2024. The increase was primarily due to a $6.2 million increase in saltwater disposal costs, as well as a $4.0 million increase in contract labor. Additionally, there has been an increase in certain other lease operating expenses as a result of an increase in well count due to acquisitions and additional wells successfully drilled and completed.

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Production and Ad Valorem Taxes

We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $22.4 million ($1.92 per Boe) for the year ended December 31, 2025 compared to $21.0 million ($2.30 per Boe) for 2024. As a percentage of oil and natural gas sales, our production taxes were 5% and 6% for the years ended December 31, 2025 and 2024, respectively.

Production taxes generally fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.

Ad valorem taxes increased during the year ended December 31, 2025 as compared to 2024, primarily due to additional wells drilled and completed and new wells acquired.

Depletion and Accretion

Depletion and accretion was $215.7 million ($18.48 per Boe) for the year ended December 31, 2025, an increase of 22% from $176.5 million ($19.31 per Boe) in 2024. The increase in depletion and accretion expense was primarily due to the increase in depletion expense resulting from the increase in production during the year ended December 31, 2025.

Impairment of Long-Lived Assets

During the years ended December 31, 2025 and 2024, we recognized impairment expense of $44.7 million and $36.4 million, respectively. As of December 31, 2025, as a result of the decline in oil prices in the Eagle Ford Basin, we compared the sum of the expected undiscounted future net cash flows to the carrying amount of the assets. As the carrying amount of the assets was higher than the expected undiscounted future net cash flows, an impairment loss of $44.7 million was recorded as the difference between the carrying value and the estimated fair value.

During the year ended December 31, 2024, as a result of widening differentials and higher production cost assumptions, it was determined that the carrying amount of proved oil and gas properties in the Bakken exceeded undiscounted future net cash flows. As a result, an impairment of $35.6 million was recorded to write-down the carrying value to the estimated fair value of the proved oil and gas properties. Additionally, for the year ended December 31, 2024, an impairment of 0.7 million to the Company's unproved properties in the Permian Basin as the operator of those properties no longer intends to drill certain locations.

General and Administrative

The following table provides components of our general and administrative expenses for the years ended December 31, 2025 and 2024:

Year Ended December 31,

(in thousands)

General and administrative expenses

Non-cash stock-based compensation

Total general and administrative expenses

Total general and administrative expenses were $31.0 million ($2.66 per Boe) for the year ended December 31, 2025, a increase of 26% from $24.6 million ($2.70 per Boe) in 2024. The increase was primarily due to severance expense incurred during the period as a result of a management transition as well as expenses related to capital market activities.

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Gain/(Loss) on Derivatives – Commodity Derivatives

The following table summarizes the amounts reported as gain (loss) on derivatives - commodity derivatives in the condensed consolidated statements of operations for the years ended December 31, 2025, and 2024:

Year Ended December 31,

(in thousands)

Net cash receipts from commodity derivatives

Oil derivatives

Natural gas derivatives

Total net cash receipts from commodity derivatives

Unrealized gain (loss) on commodity derivatives

Oil derivatives

Natural gas derivatives

Power capacity contract

Total unrealized gain (loss) on commodity derivatives

Total gain (loss) on derivatives - commodity derivatives

Our earnings are affected by the changes in the value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

Interest Expense

Interest expense was $25.5 million for the year ended December 31, 2025 compared to $18.5 million for 2024. The increase in interest expense was primarily due to a higher average outstanding balance on the revolving credit facility, as well as the issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes in November 2025. See the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources" for more information.

Income Tax Expense (Benefit)

For the year ended December 31, 2025, we recorded income tax expense of $7.8 million, which included current income tax expense of $0.4 million and deferred income tax expense of $7.4 million. Our effective income tax rate of 24.2% for the year ended December 31, 2025 differs from the federal statutory rate of 21% due primarily to the impact of certain discrete items, state income taxes, and certain nontaxable or nondeductible items. For the year ended December 31, 2024, we recorded income tax expense of $6.2 million, which included current income tax expense of $0.2 million and deferred income tax expense of $6.0 million. Our effective income tax rate of 24.9% for the year ended December 31, 2024 differed from the federal statutory rate of 21% primarily due to the impact of certain discrete items and state income taxes.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources as of the periods covered by this report have been internally generated cash flow from operations, credit facility borrowings, and the issuance of senior notes. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

As of December 31, 2025, the Company had $350.0 million of principal debt outstanding on 8.875% senior unsecured notes (the “2029 Senior Notes”) and $50.0 million of debt outstanding under our senior secured revolving credit agreement (as amended, the “Credit Agreement”). We had $339.5 million of liquidity as of December 31, 2025, consisting of $324.7 million of committed borrowing availability under the Credit Agreement and $14.8 million of cash on hand.

With our cash on hand, cash flow from operations, and borrowing capacity under the Credit Agreement, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at

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least the next twelve months. However, we may seek additional access to capital and liquidity. We cannot assure you that any additional capital will be available to us on favorable terms or at all.

Capital commitments

Our recent capital commitments have been to fund the development and acquisition of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash on hand, cash flows from operations and available borrowing capacity under our Credit Agreement. Our capital expenditures could be curtailed if our cash flows decline from expected levels.

Common stock dividends

We paid dividends of $57.7 million, or $0.44 per share, and $57.5 million, or $0.44 per share, during the years ended December 31, 2025 and 2024, respectively. On February 13, 2026, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2026 that will be paid on March 13, 2026 to stockholders of record as of February 27, 2026. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.

Stock repurchase program

In December 2022, we announced that our Board of Directors approved a stock repurchase program for up to $50.0 million of our common stock through December 31, 2023. The stock repurchase program terminated on December 31, 2023. During the year ended December 31, 2023, the Company repurchased 5,651,707 shares under the program at an aggregate cost of $36.1 million. As of December 31, 2023, the Company had repurchased a total of 5,677,627 shares since the inception of the program at an aggregate cost of $36.3 million.

Cash Flows

Our cash flows for the years ended December 31, 2025, 2024 and 2023 are presented below:

Year Ended December 31,

(in thousands)

Net cash provided by operating activities

Net cash used in investing activities

Net cash provided by financing activities

Net change in cash

Cash Flows Provided by Operating Activities

The primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our commodity derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes.

The $20.7 million increase in operating cash flows during the year ended December 31, 2025 as compared to 2024 was primarily due to the increase in oil and natural gas sales during 2025 as compared to 2024. Our net cash provided by operating activities included a benefit of $5.5 million and $0.9 million for the years ended December 31, 2025 and 2024, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash Flows Used in Investing Activities

For the year ended December 31, 2025, our net cash used in investing activities was $409.8 million, which consisted primarily of $300.8 million of capital expenditures for oil and natural gas properties and $118.5 million of acquisitions of oil and natural gas properties. These cash flows used in investing activities are partially offset by cash proceeds from refund of advances from operators of $4.3 million, and proceeds from the sale of equity investments of $5.0 million during 2025.

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For the year ended December 31, 2024, our net cash used in investing activities was $310.8 million, which consisted primarily of $285.8 million of capital expenditures for oil and natural gas properties and $61.2 million of acquisitions of oil and natural gas properties. These cash flows used in investing activities are partially offset by proceeds from the disposal of oil and natural gas properties of 14.0 million and proceeds from refund of advances from operators of $19.7 million .

Cash Flows Provided by (Used in) Financing Activities

For the year ended December 31, 2025, our net cash provided by financing activities was $118.8 million primarily due to proceeds from senior notes, net of discount, of $336.0 million, partially offset by $155.0 million of net repayments under our Credit Agreement and $57.7 million of dividends paid on our common stock.

For the year ended December 31, 2024, our net cash provided by financing activities was $33.7 million primarily due to $95.0 million of net borrowings under our Credit Agreement, partially offset by $57.5 million of dividends paid on our common stock.

Granite Ridge Credit Agreement

At December 31, 2025, the Company had outstanding borrowings of $50.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $324.7 million. The Credit Agreement is guaranteed by the restricted subsidiaries of Granite Ridge and is secured by a first priority mortgage and security interest in substantially all of the Company's and its restricted subsidiaries' assets.

On April 29, 2025, the Company and its lenders entered into the Fifth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) increase the borrowing base from $325.0 million to $375.0 million, and (ii) increase the aggregate elected commitments from $325.0 million to $375.0 million.

On November 5, 2025, the Company and its lenders entered into the Sixth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) reaffirm the borrowing base and aggregate elected commitment amounts at $375.0 million, (ii) permit the issuance of the 2029 Senior Notes (as defined below), (iii) extend the maturity date to the earliest to occur of (A) November 5, 2029 or (B) the date that is ninety-one days prior to the stated maturity date of the 2029 Senior Notes if any 2029 Senior Notes remain outstanding on such date, and (iv) adjust the interest payable on (A) SOFR loans to interest at a rate per annum equal to SOFR plus an applicable margin ranging from 275 to 375 basis points, depending on the percentage of the borrowing base utilized and (B) base rate loans to interest at a rate per annum equal to the greatest of: (a) the U.S. prime rate as publicly announced from time to time by Bank of America, N.A.; (b) the federal funds effective rate plus 50 basis points; (c) the adjusted SOFR rate for a one-month interest period plus 100 basis points; and (d) 100 basis points, plus, in the case of any base rate loan, an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized.

2029 Senior Notes

On November 5, 2025, the Company, as issuer, completed an issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes at 96.0% of par with stated maturity on November 5, 2029 (the “2029 Senior Notes”) pursuant to a note purchase agreement (the “Note Purchase Agreement”). The Company used the net proceeds from issuance of the 2029 Senior Notes to repay certain amounts under the Credit Agreement and to pay related fees and expenses. The Note Purchase Agreement allows the ability for the Company to incur up to $100.0 million of incremental notes for purposes of acquisition financing, subject to, among other things, the willingness of holders to provide such incremental notes and a pro forma net leverage ratio not greater than 2.00 to 1.00.

Interest is due to be paid at the end of each quarter, commencing December 31, 2025. In addition, the Company will repay quarterly 2.5% of the original principal amount of the notes issued on the closing date beginning on September 30, 2026. If quarterly scheduled repayments are missed, the coupon increases to 11.875% and the Company is restricted from making any dividend payments until all delinquent scheduled repayments have been fulfilled. The Company has $17.5 million included in current liabilities in our consolidated balance sheets related to quarterly principal repayments due within the next 12 months. On or after May 5, 2027 and on or prior to May 5, 2028, the Company may, at its option, redeem, at any time some or all of the 2029 Senior Notes at 103.0% of par, as set forth in the Note Purchase Agreement, plus accrued and unpaid interest, if any. Any redemption of the 2029 Senior Notes prior to May 5, 2027 is subject to payment of a make-whole amount. After May 5, 2028, the Company may redeem some or all of the Senior Notes at

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100.0% of the principal amount thereof plus accrued and unpaid interest, if any. The principal remaining outstanding at the time of maturity is required to be paid in full by the Issuer.

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

• As of December 31, 2025, we had $50.0 million of debt outstanding under our Credit Agreement. See Note 8 of the Notes to the Consolidated Financial Statements for information regarding future interest payment obligations on our Credit Agreement.

• As of December 31, 2025, we had $350.0 million of principal debt outstanding on our 2029 Senior Notes with quarterly repayments of $8.75 million beginning September 30, 2026.

• We entered into the MSA with the Manager in which we pay the Manager an annual services fee for certain Granite Ridge group costs related to the operation of our oil and gas assets and other properties of $11.75 million, subject to annual CPI-based adjustments beginning January 1, 2027. The authority to increase the Services Fee up to a maximum total of $12.5 million annually has been delegated to management. See Note 10 of the Notes to the Consolidated Financial Statements.

• We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 of the Notes to the Consolidated Financial Statements.

• We have future obligations related to the abandonment of our oil and natural gas properties. See Note 6 of the Notes to the Consolidated Financial Statements.

• With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments.

Planned Capital Expenditures

For 2026, we are budgeting approximately $320 million to $360 million in total planned capital expenditures, including approximately $20 million to $30 million of acquisitions of oil and natural gas properties. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Credit Agreement.

The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, contractual obligations, internally generated cash flow, and other factors both within and outside our control.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With our Credit Agreement and our positive cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital. We may also choose to seek additional capital rather than utilize our credit to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

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Effects of Inflation and Pricing

The oil and natural gas industry is typically very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion.

Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Critical Accounting Estimates

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions. Further, these estimates and other factors, including those outside of management’s control could have significant adverse impact to the financial condition, results of operations and cash flows of the Company.

Use of Estimates

The preparation of financial statements under U.S. GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period.

Oil and Natural Gas Reserves

The determination of depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. As of December 31, 2025, approximately 24% of our total proved reserves were categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Such information includes revisions of certain reserve estimates attributable to the properties included in the prior year’s estimates. These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices.

External petroleum engineers independently estimated all of the proved reserve quantities included in our Annual Report, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we provided them our historical information, such as oil and natural gas production, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. The third-party independent reserve engineers, NSAI, evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2025.

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Oil and Natural Gas Properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting.

The successful efforts method inherently relies on the estimation of proved oil and natural gas reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.

Depletion of oil and natural gas producing properties is determined using the units-of-production method. During the years ended December 31, 2025, 2024, and 2023, we recognized depletion expense of $214.8 million, $175.7 million and $160.2 million, respectively.

Any reduction in proved reserves could result in an acceleration of future depletion expense. Such a decline may result from lower commodity prices which may make it uneconomical to drill certain proved undeveloped locations. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of proved properties for impairment.

Holding all other factors constant, if proved reserves are revised downward, the rate at which we record depletion and accretion expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record depletion and accretion expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.

Impairment of Oil and Natural Gas Properties

All of our long-lived assets are monitored for potential impairment annually, or when circumstances indicate that the carrying value of an asset may be greater than management’s estimates of its future net cash flows, including cash flows from proved reserves and risk-adjusted probable and possible reserves. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value, using the income or market approach, and the carrying value of the assets. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to develop and produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates, and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods.

Unproved oil and natural gas properties are assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects.

Derivative Instruments – Commodity Derivatives

In order to reduce uncertainty around commodity prices received for our oil and natural gas operators’ production, we enter into commodity price derivative contracts from time to time. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties’ creditworthiness.

We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and fair value is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty

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and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.

Revenue Recognition

The Company’s revenues are derived from its interests in the sale of oil and natural gas production. As we do not operate any of our wells, we have limited visibility into the timing of when new wells start producing and production statements may not be received for one to three months or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that we will receive for the sale of the product. Engineering estimates are typically used to calculate expected volumes. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the basis differential from market on a basin-by-basin basis. The expected sales volumes and prices for these properties are estimated and recorded within the revenue receivable line item in the accompanying consolidated balance sheets. Differences between our estimates and the actual amounts received for oil and natural gas sales are recorded in the month that payment is received from the third party.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Note 2 of the Notes to the Consolidated Financial Statements.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.