Exhibit 99.4

INFORMATION ABOUT PIH

Overview

PIH is an independent energy company headquartered in Texas and founded in 2017. We are primarily engaged in oil and gas exploration and production, with operations concentrated across the Western Anadarko Basin of Texas, Oklahoma, and Kansas. Our strategy is centered on acquiring existing producing assets and applying engineering expertise to enhance performance and extend asset life. Our management team, led by Will Ulrich and Chris Hammack, possesses extensive operational and industry experience. We leverage this experience to create sustainable value by investing in long-lived reserves, reducing emissions, improving asset integrity, and generating consistent, hedged-protected cash flow.

References in this section to “we,” “our,” “us,” “the Company” or “PIH” generally refer to Presidio Investment Holdings LLC and its consolidated subsidiaries.

Our Business Model

We emphasize a disciplined approach for capital allocation, controlling costs and maintaining financial discipline to allow us to generate significant free cash flow. Our strategy is centered on acquiring existing producing assets and applying engineering expertise to enhance performance and asset life. Management places emphasis on operating cash flow in managing the business as operating cash flow considers the cash expenses incurred during the period and excludes non-cash expenditures not directly related to operations. Our culture of cost control and production optimization has resulted in substantially lower cash operating costs than our peers.

Our Properties

Our assets are located throughout Texas, Oklahoma, and Kansas, consisting of approximately 1,877 net operated and non-operated proved developed producing wells. For the year ended December 31, 2025, our average net daily production was approximately 21.1 MBoe/d. Our wells are located exclusively in the Anadarko Basin, which has a more predictable production profile compared to less mature basins. Our production benefits from both the diversity of our well vintage and the lack of concentration in any specific sub-area. Within our large and diversified proved developed producing base, no single well accounts for more than 0.78% of our proved developed producing PV-10.

Within our operating areas, our assets are prospective for multiple formations. Our experience in the Western Anadarko Basin and these formations allows us to generate significant free cash flow from these low declining assets in a variety of commodity price environments.

The following table presents our historical estimated oil, natural gas and NGL proved reserves as of December 31, 2025.

Development Plan and Capital Budget

Our business plan has historically been focused on acquiring and then exploiting the production of our assets. Funding sources for our acquisitions have included proceeds from borrowings under the RBL Facility, contributions from our equity partners, the issuance of asset-backed securities and cash flow from operating activities. We spent approximately $0.7 million in 2024 on development costs and spent approximately $3.4 million in 2025 on development costs.

During the year ended December 31, 2024, we spent approximately $1.3 million on remedial workovers and other capital projects, $2.9 million on property and equipment capital projects, and $2.2 million on acquisitions. We also divested $1.4 million of non-operated interests to the respective operators during this period. During the year ended December 31, 2025, we spent approximately $4.2 million on remedial workovers and other capital projects, $2.1 million on property and equipment capital projects, and made no acquisitions.

Our development plan and capital budget are based on management’s current expectations and assumptions about future events. While we consider these expectations and assumptions to be reasonable, they are subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, prevailing and anticipated commodity prices, the availability of necessary equipment, infrastructure, labor and capital, the receipt and timing of required regulatory permits and approvals and seasonal conditions.

Our Operations

Oil and Gas Reserves and Operating Data

Reserve data

The information with respect to our estimated proved reserves based on SEC Pricing (as defined below) presented below has been prepared in accordance with the rules and regulations of the SEC.

Reserves Presentation

The following tables provide a summary of our estimated proved reserves and related PV-10 of proved reserves as of December 31, 2025, using SEC Pricing, based on evaluations prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent reserve engineer. See “— Preparation of Reserve Estimates” for the definitions of proved and probable reserves and the technologies and economic data used in their estimation. Prices were adjusted for quality, energy content, transportation fees and market differentials, as applicable.

Summary Reserve Data

Our historical SEC reserves, PV-10 and standardized measure of proved reserves were calculated using oil and gas price parameters established by current SEC guidelines, including the use of an average effective price, calculated as prices equal to the 12-month unweighted arithmetic average of the first day of the month prices for each of the preceding 12 months as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”). These prices were adjusted for differentials on a per-property basis, which may include local basis differential, fuel costs and shrinkage. All prices are held constant throughout the lives of the properties.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “— Oil and Gas Reserves and Operating Data — Reserve Data” in evaluating the material presented below.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2025 included in this proxy statement/prospectus are based on evaluations prepared by the independent petroleum engineering firm of CG&A in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.

Under SEC rules, proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and other data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data and well-test data.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil, natural gas or NGLs that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas or NGLs that are ultimately recovered. Estimates of economically recoverable natural gas and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Risk Factors” appearing elsewhere in this proxy statement/prospectus on Form S-4 (File No. 333-290090) (as amended and supplemented) filed by Presidio Production Company (f/k/a Presidio PubCo Inc.) and declared effective by the Securities and Exchange Commission on January 30, 2026 (the “Registration Statement”).

Internal Controls

Our internal staff of petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their preparation of reserve estimates. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “Risk Factors — Risks Related to PIH’s Business and to Presidio’s Business Following the Business Combination — Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” for more information. The reserves engineering group is responsible for the internal review of reserve estimates, and the technical person employed by us at the time who was primarily responsible for overseeing the preparation of our reserve estimates included in this proxy statement/prospectus has more than 18 years of experience as a reserve engineer and was directly responsible for overseeing the reserves engineering group. The technical person currently primarily responsible for overseeing the preparation of our reserve estimates has more than 12 years of experience in reserve engineering. The reserves engineering group reviews the estimates with our third-party petroleum consultants, CG&A, an independent petroleum engineering firm.

CG&A is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. The lead evaluator that prepared the reserve report was W. Todd Brooker, President at CG&A.

Todd has been with CG&A since 1992 and graduated from the University of Texas at Austin in 1989 with a bachelors degree in Petroleum Engineering. Todd is a State of Texas registered professional engineer (License #83462) and a member of the Society of Petroleum Engineers. Todd meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; Todd is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Proved Undeveloped Reserves (PUDs)

We aim to obtain proved developed producing wells through acquisitions in accordance with our growth strategy rather than through development activities. We accordingly contribute limited capital to development activities. From time to time, when acquiring packages of wells, we will acquire certain locations that are in development by the acquiree at the time of the acquisition or could be developed in the future. Presidio typically monetizes its PUD locations through farm-out arrangements that generally do not require capital investment by Presidio. In compliance with SEC rules, Presidio only books PUD locations for which the farm-out counterparty has represented that the related well is included on its drilling schedule for the next calendar year.

As of December 31, 2025, our proved undeveloped reserves were composed of 0.0 MBbls of oil, 0.0 MBbls of NGLs and 0.0 MMcf of natural gas for a total of 0.0 MBoe.

The following table summarizes our changes in PUDs, for the year ended December 31, 2025 (in MBoe):

During the year ended December 31, 2025, revisions to prior estimates reduced proved reserves by 93.8 MBoe, primarily due to completion complications that shortened the producing interval on one well. Additional revisions reflect a slight adjustment to net revenue interest based on the actual completion interval. These revisions were associated with prior-year PUD reserves converted to proved developed during the year. There were no additional or deleted PUDs during the year ended December 31, 2025.

Additionally, we converted 20.2 MBoe of PUDs into proved developed reserves in 2025. Costs incurred relating to the development of all oil and natural gas reserves were $0.3 million during the year ended December 31, 2025.

Oil, Natural Gas and NGL Production Prices and Production Costs

Production and Price History

We currently only have production in the Anadarko Basin. The following table sets forth information regarding our production and operating data for the periods indicated.

Production data:

Average realized sales prices:

Expense per Boe:

Operating Data

The following table sets forth information regarding our revenues, net production volumes, average realized prices and operating expenses for the year ended December 31, 2024 and the year ended December 31, 2025:

Proved Developed Producing Wells

The following table sets forth information regarding our proved developed producing wells as of December 31, 2025:

Developed and Undeveloped Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2025:

All of our leasehold acreage is held by production and located in the Anadarko Basin.

Drilling Results

The table below sets forth the results of our operated drilling activities for the periods indicated. Additionally, the table sets forth the results of non-operated drilling activities in which the company has financial exposure to the drilling and completion operations. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry holes are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

We drilled no exploratory wells (productive or dry) during the year ended December 31, 2025 or the year ended December 31, 2024.

The following table sets forth information regarding our drilling activities as of December 31, 2025 and December 31, 2024, including with respect to our operated wells we have begun drilling and those which are drilled and awaiting completion.

As of December 31, 2025, the Company did not drill or complete any wells. Additionally, as of December 31, 2025, the Company had elected to participate in 0 non-operated gross wells (0 net) that were in process of drilling and completion.

As of December 31, 2024, the Company did not drill or complete any wells. Additionally, as of December 31, 2024, the Company had elected to participate in 0 non-operated gross wells (0 net) that were in process of drilling and completion.

As of December 31, 2025, we were not a party to any long-term drilling rig contracts.

Productive Wells

As of December 31, 2025, we owned interests in the following number of productive wells:

Marketing and Customers

We market production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to purchasers at market prices.

For the year ended December 31, 2024 and the year ended December 31, 2025, the following companies each represented greater than 10% of our oil and gas accounts receivable balance:

Gathering & Processing Agreements

We incur gathering and processing expense under various gathering and/or processing agreements with third-party midstream providers. None of our gathering and/or processing agreements includes minimum volume commitments.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in evaluating and bidding for oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Seasonality of business

Generally, demand for natural gas, oil and NGL decreases during the spring and fall months and increases during the summer and winter months. However, certain natural gas and NGL markets utilize storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In addition, seasonal anomalies such as mild winters or mild summers can have a significant impact on prices. These seasonal anomalies can pose challenges for meeting our objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages, increased costs or delayed operations.

Title to properties

We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring producing wells, we endeavor to perform a title investigation on an appropriate portion of the properties that is thorough and is consistent with standard practice in the oil and natural gas industry. Generally, we conduct a title examination and perform curative work with respect to significant defects that we identify on properties that we operate. We believe that we have performed reasonable and protective title reviews with respect to an appropriate cross-section of our operated natural gas and oil wells.

Legislative and regulatory environment

Our oil, natural gas and natural gas liquids (“NGLs”) exploration, development, production and related operations and activities are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with such rules and regulations can result in administrative, civil or criminal penalties, compulsory remediation and imposition of natural resource damages or other liabilities. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, we believe these obligations generally do not impact us differently or to any greater or lesser extent than they affect other operators in the oil and natural gas industry with similar operations and types, quantities and locations of production.

Regulation of production

In many states, oil and natural gas companies are generally required to obtain permits for drilling operations, provide drilling bonds, file reports concerning operations and meet other requirements related to the exploration, development and production of natural gas, oil and NGLs. Such states also have statutes and regulations addressing conservation matters, including provisions for unitization or pooling of natural gas and oil interests, rights and properties, the surface use and restoration of properties upon which wells are drilled and disposal of water produced or used in the drilling and completion process. These regulations include the establishment of maximum rates of production from natural gas and oil wells, rules as to the spacing, plugging and abandoning of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production, as well as rules governing the surface use and restoration of properties upon which wells are drilled.

These laws and regulations may limit the amount of natural gas, oil and NGLs that can be produced from wells in which we own an interest and may limit the number of wells, the locations in which wells can be drilled, or the method of drilling wells. Additionally, the procedures that must be followed under these laws and regulations may result in delays in obtaining permits and approvals necessary for our operations and therefore our expected timing of drilling, completion and production may be negatively impacted. These regulations apply to us directly as the operator of our leasehold. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of sales and transportation of liquids

Sales of condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress has enacted price controls in the past and could reenact such controls in the future.

Our sales of NGLs are affected by the availability, terms and cost of transportation. The transportation of NGLs in common carrier pipelines is subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil, NGLs and other liquid pipeline transportation rates under the Interstate Commerce Act. In general, interstate liquids pipeline rates are set using an annual indexing methodology, however, a pipeline may also use a cost-of-service approach, settlement rates or market-based rates in certain circumstances.

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of liquids transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of transportation and sales of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (the “NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the “NGA”) and the NGPA, and by regulations and orders promulgated by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The Energy Policy Act of 2005 (the “EP Act of 2005”) amended the NGA and NGPA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC. The EP Act of 2005 also provided FERC with the power to assess civil penalties of up to $1,000,000 per day (adjusted annually for inflation) for violations of the NGA and NGPA. As of 2025, the new adjusted maximum penalty amount is $1,584,648 per violation, per day. The civil penalty provisions are applicable to entities that engage in the sale and transportation of natural gas for resale in interstate commerce.

On January 19, 2006, FERC issued Order No. 670, implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The resulting rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-FERC jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services. FERC also interprets its authority to reach otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704, described below. However, in October 2022, the Fifth Circuit ruled that FERC’s jurisdiction to regulate market manipulation is limited to interstate transactions only and does not reach intrastate natural gas transactions.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. As a result of these orders, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including oil and natural gas producers, gatherers and marketers, are now required to report, by May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance provided by FERC. Market participants must also indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transportation services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering facilities function or a jurisdictional transportation function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain non-jurisdictional gathering facilities as jurisdictional transportation facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services could be the subject of ongoing litigation, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

In addition, the pipelines in the gathering systems on which we rely may be subject to regulation by the U.S. Department of Transportation. The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. Over the past several years PHMSA has taken steps to expand the regulation of rural gathering lines and impose a number of reporting and inspection requirements on regulated pipelines, and additional requirements are expected in the future. On November 15, 2021, PHMSA released a final rule that expands the definition of regulated gathering pipelines and imposes safety measures on certain currently unregulated gathering pipelines. The final rule also imposes reporting requirements on all gathering pipelines and specifically requires operators to report safety information to PHMSA. The future adoption of laws or regulations that apply more comprehensive or stringent safety standards could increase the expenses we incur for gathering service.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical and financial sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and by the Commodity Futures Trading Commission (the “CFTC”) under the Commodity Exchange Act (the “CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act, and regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity as well as certain disruptive trading practices. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. As such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC, PHMSA, the CFTC, or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC, PHMSA, the CFTC, or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other oil and natural gas producers and marketers with which we compete.

Regulation of environmental and occupational safety and health matters generally

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing environmental protection, occupational safety and health, and the release, discharge or disposal of materials into the environment, some of which carry substantial administrative, civil and criminal penalties for failure to comply. Applicable U.S. federal environmental laws include, but are not limited to, the CERCLA, the CWA and the CAA. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants, and other matters. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling, and production operations; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit construction or drilling activities in sensitive areas such as wilderness, wetlands, frontier and other protected areas; require investigatory or remedial actions to prevent or mitigate pollution conditions caused by our operations; impose obligations to reclaim and abandon well sites and pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, loss of leases, the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. It is possible that, over time, environmental regulation could evolve to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal, or remediation requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our business, there can be no assurance that this will continue in the future.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes

CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These classes of persons, or, as termed in CERCLA, potentially responsible parties, include the current and past owners or operators of a disposal site or site where the release occurred and anyone who disposed or arranged for the disposal of the hazardous substances found at such sites. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA and other environmental laws but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect our business operations. While petroleum and crude oil fractions are generally not considered hazardous substances under CERCLA and its analogues because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

We also generate solid and hazardous wastes that may be subject to the requirements of the RCRA, and analogous state laws. RCRA regulates the generation, handling, storage, treatment, transport and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes “drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy” from regulation as hazardous wastes. With the approval of the EPA, individual states can administer some or all of the provisions of RCRA and some states have adopted their own, more stringent requirements. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are determined to have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that may have been used by prior owners or operators for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations where such substances have been taken for recycling or disposal. In addition, some of our properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and/or analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water discharges

The Federal Water Pollution Control Act, also known as the CWA, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other natural gas wastes, into or near waters of the United States or state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of federal jurisdiction under the CWA over these regulated waters continues to be subject to significant uncertainty and litigation. The EPA and the Corps issued a final rule on the federal jurisdictional reach over waters of the United States in 2015, which never took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. The EPA and Corps underwent a further rulemaking process to attempt to redefine the definition of waters of the United States; however, the U.S. Supreme Court’s decision in Sackett v. EPA invalidated the prior test used by the EPA to determine whether wetlands qualify as navigable waters of the United States, and on September 8, 2023, the EPA and the Corps published a final rule to align the definition of “waters of the United States” with the U.S. Supreme Court’s decision in Sackett v. EPA. In March 2025, the EPA and the Corps announced their intention to undertake a rulemaking process to revise the 2023 rule. On November 20, 2025, the EPA and the Corps published a proposed rule to revise the definition of “waters of the United States” under the CWA to comply with the Sackett decision, with comments due by January 5, 2026, which could reduce the number and size of federally jurisdictional waters. To the extent any new rules or court decisions expand the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas.

The process for obtaining permits also has the potential to delay our operations. For example, on June 18, 2025, the Corps issued a proposal to reissue and modify “Nationwide Permits” that authorize certain dredge and fill activities in jurisdictional wetlands related to pipeline projects, including Nationwide Permit 12 (“NWP 12”), the general permit issued by the Corps for pipelines and utility projects. Any changes to NWP 12 could have an impact on our business. If new oil and gas pipeline projects are unable to utilize NWP 12 or identify an alternate means of CWA compliance, such projects could be significantly delayed. Additionally, spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” are required by federal law in connection with on-site storage of significant quantities of oil. Compliance may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak.

Safe Drinking Water Act

The SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans. The SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. The EP Act of 2005 amended the Underground Injection Control provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for enhanced oil recovery is not excluded. In 2014, the EPA issued permitting guidance governing hydraulic fracturing with diesel fuels. While we do not currently use diesel fuels in our hydraulic fracturing fluids, we may become subject to federal permitting under the SDWA if our fracturing formula changes.

Air emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion. The EPA is currently reconsidering its 2020 decision to retain the 2015 NAAQS. Further, in June 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. These rules could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements.

If the EPA were to adopt more stringent NAAQS for ozone, under the CAA, state implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted rules under the CAA that require the reduction of volatile organic compound and methane emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. On July 4, 2025, President Trump signed the One Big Beautiful Bill into law which, among other things, postpones the EPA’s imposition of the recent methane Waste Emissions Charge to 2034, lowers royalties on federal onshore oil and gas leases, and repeals a royalty imposed on waste methane produced from federal oil and gas leases. On July 29, 2025, the EPA issued an interim final rule extending several compliance deadlines associated with the 2024 New Source Performance Standards (“NSPS OOOOb”) and Emissions Guidelines (“EG OOOOc”) for the oil and gas industry. NSPS OOOOb and EG OOOOc were published in March 2024 and took effect in May 2024. EPA announced its intention to reconsider NSPS OOOOb and EG OOOOc in March 2025. On July 29, 2025, EPA released a pre-publication proposed rule which would rescind EPA’s 2009 final rule under the Clean Air Act finding that GHGs endanger the public health and welfare of current and future generations and that emissions of GHGs from new motor vehicles contribute to GHG pollution that threatens the public health and welfare. On September 16, 2025, the EPA announced a proposal to end the Greenhouse Gas Reporting Program (“GHGRP”) for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. As a result, there remains considerable uncertainty surrounding regulation of GHG and methane emissions from oil and gas operations.

Oil Pollution Act

The OPA establishes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties, including owners and operators of certain facilities from which oil is released, related to the prevention of oil spills and liability for damages resulting from such spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to NEPA. NEPA requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of an environmental assessment and, if necessary, an environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action have the potential to significantly impact the environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, may increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases. However, the current administration has taken actions to revise the scope of NEPA reviews and the U.S. Supreme Court has recently limited the scope of federal agencies’ obligations related to environmental review pursuant to NEPA in Seven County Infrastructure Coalition v. Eagle County. While these changes are aimed at streamlining NEPA reviews, the ultimate result of these changes is unknown at this time.

Endangered Species Act and Migratory Bird Treaty Act

The ESA restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the MBTA. To the extent that species that are listed under the ESA or similar state laws, or are protected under the MBTA, inhabit the areas where we conduct operations, our operations could be adversely impacted. Moreover, drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Climate change

The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG disclosure obligations and regulations that directly limit GHG emissions from certain sources. As a result, our operations are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and the emission of GHGs.

If more stringent laws and regulations relating to climate change and GHGs are adopted, it could cause us to incur material expenses to comply with such laws and regulations. These requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

For example, there are a number of state and regional efforts to regulate emissions of methane from new and existing sources within the oil and natural gas source category. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, and increased frequency of maintenance and repair activities to address emissions leakage at certain well sites and compressor stations, and also may require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs, although the current U.S. presidential administration has opposed action aimed at limiting GHG emissions. At the international level, in April 2016, the U.S. joined the international community at the 21^st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set GHG emission reduction goals every five years beginning in 2020. In January 2025, the U.S. submitted its notice to withdraw from the Paris Agreement, with the withdrawal effective on January 27, 2026. Additionally at the international level, the International Court of Justice issued an advisory opinion on July, 23, 2025, stating that all nations have certain obligations to prevent significant harm to the environment under customary duties of international law, which the International Court of Justice interpreted to include the obligation to mitigate climate change, including by the domestic regulation of fossil fuel-related industrial activities and other private actors. It remains uncertain how the International Court of Justice’s advisory opinion could be interpreted or otherwise acted on by nations or other actors, including in ways that could affect our business operations.

Separately, many U.S. state and local leaders and foreign governments have intensified or stated their intent to intensify efforts to support international climate commitments and treaties and have developed programs that are aimed at reducing GHG emissions, such as by means of cap and trade programs, carbon taxes, encouraging the use of renewable energy or alternative low-carbon fuels, or imposing new climate-related reporting requirements. Cap and trade programs, for example, typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Any legislation or regulatory programs aimed at reducing GHG emissions, addressing climate change more generally, or requiring the disclosure of climate-related information could increase the cost of consuming, and thereby reduce demand for, the oil, natural gas or NGLs we produce or otherwise have an adverse effect on our business, financial condition and results of operations.

There are also increasing financial risks for fossil fuel producers as shareholders, bondholders and lenders currently may elect in the future to shift some or all of their investments into non-fossil fuel energy-related sectors. Certain institutional lenders who provide financing to fossil-fuel energy companies also have shifted their investment practices to those that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies in the short or long term. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will assess financed emissions across their portfolios and take steps to quantify and reduce those emissions. There is also a risk that financial institutions will be pressured or required to adopt policies limiting funding for the fossil fuel sector. Although there has been recent political support to counteract these initiatives, these and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Any material reduction in the capital available to us could make it more difficult to secure funding for exploration, development and production activities and have an adverse effect on our business, financial condition and results of operations.

Hydraulic fracturing

Hydraulic fracturing is a common practice that is used to stimulate production of oil and/or natural gas from low permeability subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the hydrocarbon-bearing rock formation and stimulate production of hydrocarbons. Presently, hydraulic fracturing is primarily regulated at the state level, typically by state natural gas commissions, but the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels in fracturing fluid and published guidance for such activities.

At the state level, a growing number of states, including the states in which we conduct operations, have adopted or are considering regulations that could impose more stringent permitting, disclosure or well construction and monitoring requirements on hydraulic fracturing activities. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record-keeping obligations, plugging and abandonment requirements and attendant permitting delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential legislation or regulation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Worker health and safety

We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. For example, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we maintain, organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Related permits and authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Related insurance

We maintain insurance against some contamination risks associated with our development activities, including a coverage policy for gradual pollution events. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Human Capital Resources

We aim to provide a safe, healthy, respectful, and fair workplace for all employees. We believe our employees’ talent and wellbeing is foundational to delivering on our corporate strategy, and that intentional human capital management strategies enable us to attract, develop, retain and reward our dedicated employees.

As of December 31, 2025, we had 135 total employees, 125 of whom were full-time employees. From time to time, we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. In general, we believe that employee relations are satisfactory.

Employee Safety and Health

The health, safety, and well-being of our employees is a top priority. In addition to our commitment to complying with all applicable safety, health, and environmental laws and regulations, we are focused on minimizing the risk of workplace incidents and preparing for emergencies as a priority element of our culture. We work to reduce safety incidents in our business and actively seek opportunities to make safety culture and procedural improvements.

Legal proceedings

The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. The Company is not currently a party to any material legal proceedings. In addition, the Company is not aware of any material legal proceedings contemplated to be brought against the Company.

The Company, as an owner and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of December 31, 2025. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.