Prairie Operating - 10-K annual report 2025

In July 2025, we entered into an agreement to acquire certain assets from Edge Energy for a total purchase price of $12.5 million payable in cash, subject to certain closing adjustments (the “Edge Acquisition”). We closed the Edge Acquisition on July 3, 2025, which included the acquisition of 13 operated wells on approximately 11,300 net acres. We funded the transaction by borrowing under our amended and restated reserve–based credit agreement (the “Credit Facility”) with Citibank, N.A. (“Citi”). In October 2025, we entered into agreements to acquire certain assets from Summit Oil & Gas, LLC. (“Summit”) and Crown Exploration II, Ltd (“Crown”) for a total purchase price of $2.3 million payable in cash, subject to certain closing adjustments (the “Summit and Crown Acquisitions”). The Summit and Crown Acquisitions included the acquisition of five operated wells on approximately 3,400 net acres. We refer to the assets we acquired in the Bayswater Acquisition, the Edge Acquisition, and the Summit and Crown Acquisitions as the “Central Weld Assets.”

As of December 31, 2025, the Central Weld Assets cover approximately 45,000 net leasehold acres, on and under approximately 56,200 gross acres and 177 gross proved undeveloped locations. Approximately 87% of the net leasehold of our Central Weld Assets are held by production and 95% of the acreage is leased from private landowners, with the remaining 5% under State of Colorado or Federal leases. The remaining 13% of the Central Weld Assets acreage not held by production have varying expiration dates, some with options to extend ranging from one to two years. The Central Weld Assets fee leases are burdened with average royalties of 20%. The leases can be held indefinitely by production and unless production is established within the spacing units covering the undeveloped acreage, the leases for such acreage will eventually expire.

Development Plan and Permitting. We began executing the development plan of our Central Weld Assets in the second quarter of 2025 by completing nine wells on the Opal/Coalbank pad and drilling 11 gross wells on the Rusch pad, which came online in September 2025. After completing drilling at our Rusch pad, we drilled our Noble pad development, consisting of seven gross wells, and our Simpson pad, consisting of six gross wells, both of which came online in the fourth quarter of 2025. We finished the year by drilling a 10 gross well development consisting of five wells in our Blehm North drilling spacing unit (“DSU”) and five wells in our Schneider DSU. These ten wells are expected to be completed in the first quarter of 2026. Additionally, we began drilling a nine well development in our Elder East and West DSUs, which is expected to be completed in the early in the second quarter of 2026.

Our reserve estimates as of December 31, 2025 and 2024, are based on a reserve report prepared by Cawley, Gillespie & Associates Inc. (“CG&A”) in accordance with the rules and regulations of the SEC in Regulation S–X, Rule 4–10, and do not include probable or possible reserves. All of our proved reserves presented below are located in the DJ Basin.

The following table presents our estimated proved reserves by category, the standardized measure of discounted future net cash flows, PV–10, and the prices used in the calculation of net proved reserves estimates for the years indicated:

PV–10 is a financial measure not presented in accordance with U.S. GAAP. PV–10 is derived from Standardized Measure, which is the most directly comparable GAAP financial measure for proved reserves. PV–10 is a computation of the Standardized Measure on a pre–tax basis and is equal to the Standardized Measure at the applicable date, before deducting future income taxes discounted at 10%. Neither PV–10 nor the Standardized Measure represents an estimate of the fair market value of the applicable crude oil, natural gas, and NGLs properties. We believe that the presentation of PV–10 is relevant and useful to our investors as supplemental disclosure to the Standardized Measure, or after–tax amount, because it presents the discounted future net cash flows attributable to our reserves before considering future corporate income taxes and our current tax structure. PV–10 has limitations as a financial measure since it excludes future income taxes and should not be considered as an alternative to, or more meaningful than, Standardized Measure calculated in accordance with GAAP.

The following table provides a reconciliation of the Standardized Measure to the PV–10 of our estimated proved reserves for the years indicated:

Management reviews all proved undeveloped reserves on an annual basis to ensure an appropriate plan for development exists. As per SEC rules, all of our proved undeveloped reserves are required to be converted to proved developed reserves within five years of the date they are first booked as proved undeveloped reserves, unless the reserves are associated with an existing producing zone. We expect that development costs associated with our estimated proved undeveloped reserves as of December 31, 2025 will require us to invest an additional $689.6 million for those reserves to be brought to production. Our ability to make the necessary investments to generate these cash inflows is subject to factors that may be beyond our control. Refer to Risk Factors – The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not ultimately be developed or produced.

For additional information, refer to Part II – Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

In–progress development wells consist of wells which are in the process of being drilled or have been drilled and are waiting to be completed and/or for pipeline connection. All of the in–progress wells presented below came online throughout the first quarter of 2026.

Our properties are subject to customary royalty interests, overriding royalty interests, obligations incident to operating and joint venture agreements, liens for current taxes, other industry–related constraints, and certain other leasehold restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business. We believe that we have satisfactory title to all of our producing properties. Although title to our properties is subject to complex interpretation of multiple conveyances, deeds, reservations, and other instruments that serve to affect mineral title, we believe that none of these risks will materially detract from the value of our properties or from our interest therein or otherwise materially interfere with the operation of our business.

Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. In an effort to reduce the impact of price volatility, and in compliance with requirements under our Credit Facility, we enter into derivative contracts to economically hedge a portion of our estimated production from our proved, developed, producing oil and natural gas properties against adverse fluctuations in commodity prices. By doing so, we believe we can mitigate, but not eliminate, the potential negative effects of decreases in oil and natural gas prices on our cash flows from operations. However, our hedging activity could reduce our ability to benefit from increases in oil and natural gas prices. Further, we could sustain hedge losses to the extent our oil and natural gas derivative contract prices are lower than market prices and, conversely, we could recognize gains to the extent our oil and natural gas derivative contract prices are higher than market prices. For additional information, refer to Part II – Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We closed the Bayswater Acquisition in March 2025 and fully took over operations of the assets acquired in the Bayswater Acquisition in the third quarter of 2025. During the integration of the Bayswater Acquisition, we renegotiated certain purchaser agreements associated with the assets acquired and as a result certain purchasers which were customers at the close of the acquisition are no longer customers. During the second half of 2025, two of our largest customers accounted for approximately 83% and 10% of our oil, natural gas, and NGL revenues. While the loss of a single purchaser may result in a temporary interruption in sales of, or a lower price for, our production, we do not believe the loss of any single purchaser would have a material impact our business because we believe we could readily find alternative purchasers in our producing region.

The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that often have greater resources. Many of these companies explore for, produce, and market oil and natural gas, carry on refining operations, and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, attracting and retaining qualified personnel, and obtaining transportation for the oil and natural gas we produce. There is also competition between producers of oil and natural gas and other industries producing alternative 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 federal, state, and local governments; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing, or producing oil and natural gas and may prevent or delay the commencement or continuation of certain operations. The effect and potential impacts of these risks are difficult to accurately predict.

We believe that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows, or results of operations. However, current regulatory requirements may change, currently unforeseen environmental, health, or safety incidents may occur, or past noncompliance with environmental, health and safety laws or regulations may be discovered, any of which could have a material adverse effect on our financial position, cash flows, or results of operations. Additionally, any other new requirements of the Colorado Energy & Carbon Management Commission (“CECMC”) or other federal, state and local governmental bodies, could make it more difficult and costly to develop new oil and natural gas wells and to continue to produce existing wells, increase our costs of compliance and doing business, and delay or prevent development in certain areas or under certain conditions. We cannot assure that the existing rules, as implemented, or any future rulemaking, will not have a material and adverse impact on our financial position, cash flows, or results of operations.

In addition, governmental, scientific, and public concern over the threat of climate change arising from increasing global emissions of greenhouse gases (“GHGs”) has resulted in higher political and regulatory scrutiny in the U.S., including climate change–related pledges made by certain administrations. Former President Biden identified addressing climate change as a priority under his administration and issued executive orders in furtherance of that priority. Although President Trump’s administration has eliminated many of the Biden–era restrictions, future administration changes could result in new restrictions on GHG emissions that directly or indirectly impact our exploration, production, and development activities, or affect the demand for our products, which could have a material adverse effect on our business and financial position.

The federal Energy Policy Act of 2005 (“EPAct of 2005”) introduced significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct of 2005 amended the NGA to add an anti–market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore, provides FERC with additional civil penalty authority. The EPAct of 2005 provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day, with such penalties adjusted regularly for inflation. For example, in January 2025, the maximum penalty increased to $1,584,648 per violation per day to account for inflation. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti–market manipulation provision of the EPAct of 2005, and subsequently denied rehearing. The 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: (1) use or employ any device, scheme, or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) 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–jurisdictional sales or gathering. However, it does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non–jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti–market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

Natural gas gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities and services from regulation by FERC as a “natural gas company” under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non–jurisdictional gathering 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 jurisdictional transportation facilities as non–jurisdictional gathering facilities, and depending on the scope of that decision, our costs of delivering gas to point–of–sale locations may increase.

State regulation of natural gas gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory–take requirements. Although nondiscriminatory–take regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non–hazardous solid wastes. Pursuant to rules issued by the EPA, states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development and production of oil, natural gas, and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non–hazardous solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non–hazardous solid wastes could be classified as hazardous wastes in the future. In addition, in the course of our operations, we may 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 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.

The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by permit. The EPA and the U.S. Army Corps of Engineers (the “Corps”) have issued rules attempting to clarify the federal jurisdictional reach over WOTUS since 2015, including the Navigable Waters Protection Rule during the first Trump administration, rules reverting back to the 1986 WOTUS definition during the Biden administration, and rules reinstating the pre–2015 definition in January of 2023. However, in May 2023, the Supreme Court decided Sackett v. EPA, which sharply curtailed the EPA’s and Corps’ jurisdictional reach by limiting the types of wetlands that fell under WOTUS. Sackett codified the definition of WOTUS as only geographical features that are described in ordinary parlance as “streams, oceans, rivers, and lakes” and to adjacent wetlands that are “indistinguishable” from those bodies of water due to a continuous surface connection. In September 2023, the EPA and the Corps published a direct–to–final rule redefining WOTUS to amend the January 2023 rule and align with the decision in Sackett. The final rule eliminated the “significant nexus” test from consideration when determining federal jurisdiction and clarified that the CWA only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water. The final rule is currently subject to challenges in federal district courts. As such, uncertainty remains with respect to future implementation of the rule and any resulting litigation. In addition, in November of 2025, the EPA and the Corps issued a proposed rule to further narrow the scope of federal jurisdiction under the CWA. It is likely that this proposed rule, if finalized, will also be challenged.

In the course of our operations, we produce water in addition to natural gas, crude oil and NGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non–producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near below–ground disposal wells used for the injection of natural gas– and oil–related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies, as well as the owners of underground injection wells. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability.

The federal Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. 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 our projects. Recently, there has been increased regulation with respect to air emissions from the oil and natural gas sector.

In June 2016, the EPA published final New Source Performance Standards (“NSPS”) at 40 CFR Part 60, Subpart OOOOa establishing new air emission controls for methane and volatile organic compound (“VOC”) emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, as an iteration to the previous standards at Subpart OOOO. The EPA announced the latest iterations on these standards, Subpart OOOOb and OOOOc, on December 2, 2023. These rules require the phase–out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations, as well as emissions standards for existing sources. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources followed by three years from the plan submission deadline for existing sources to comply. However, in July 2025, the EPA extended the two–year deadline to January 2027. The regulations are subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. In addition, the new rules have been appealed by various parties and it is also possible that the new presidential administration will seek to revise or retract these rules. As a result, future implementation of the standards is uncertain at this time.

The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air–quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment.

In addition, the SEC issued a final rule in March 2024 that would mandate disclosure of climate–related risks, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. Compliance dates under the final rule were to be phased in by registrant category with some filers required to incorporate the disclosures in fiscal year 2025 filings. However, the rule was challenged and, in March of 2025, the SEC voted to withdraw its defense of the new disclosure rules. The rules have not been rescinded, although the U.S. Court of Appeals for the Eighth Circuit has ordered that litigation be held in abeyance until such time as the SEC either reconsiders the rules or resumes its defense of the rules.

Also, the United Nations–sponsored Paris Agreement calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. However, the Paris Agreement does not impose any binding obligations on its participants. Former President Biden recommitted the U.S. to the Paris Agreement and, in April 2021, announced a goal of reducing the U.S.’ emissions by 50–52% below 2005 levels by 2030. Incremental reduction measures have been agreed to at subsequent meetings, Conference of the Parties (“COP”) 26 held in Glasgow in November 2021, COP27 held in Sharm–El Sheik in November 2022, COP28 held in Dubai in November to December 2023 and COP29 held in Baku in November 2024. Relatedly, the U.S. and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector, which was reaffirmed at COP27. However, on January 20, 2025, President Trump signed an executive order to start the process of withdrawing the U.S. from the Paris Agreement. This signals that the U.S. will also not provide funding or otherwise adhere to the nonbinding commitments made in subsequent COPs, although a future President may choose to rejoin the Paris Agreement.

In addition, the Inflation Reduction Act of 2022 (the “IRA”), signed by former President Biden in August 2022, provides significant funding and incentives for research and development of low–carbon energy production methods, carbon capture, and other programs directed at addressing climate change. The IRA also includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. On November 18, 2024, the EPA published a final rule imposing a charge for “waste methane” emissions from the oil and gas sector. The amount of the charge would have started at $900 per metric ton of methane emitted in 2024, $1,200 per metric ton for emissions in 2025 and $1,500 per metric ton for 2026 and beyond. This rule may result in significant costs for our operations. However, in early 2025 Congress used the Congressional Review Act to void the implementing rule. A future Congress could implement a similar methane charge in the future.

We are subject to the requirements of the OSHA and comparable state statutes, the purpose of which is to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right–to–Know Act, comparable state statutes and any implementing regulations require that we 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.

In April 2019, Colorado Senate Bill 19–181 (“SB 181”) became effective, which substantially changes the state’s regulation of oil and natural gas exploration and production activities. SB 181 changed the CECMC’s mission from “fostering” responsible and balanced development “consistent with protection” of public health and the environment to “regulating” development “to protect” public health and the environment. SB 181 also instituted several state–wide regulatory changes, namely it: (i) changed Colorado’s statutory pooling provisions to require an applicant to own, or obtain the consent of, more than 45% of the applicable working or mineral interest, whereas previously the consent of only one mineral interest owner was required; (ii) requires that, after production is established, an applicant must pay force–pooled working or mineral interest owners a 16% royalty on oil production and a 13% royalty on gas production; (iii) changed state pre–emption law to afford local governments greater control over oil and natural gas siting; and (iv) initiated a comprehensive rulemaking to amend CECMC’s rules consistent with the agency’s revised mission.

Among the most significant changes under SB 181 was the aforementioned provision giving local governments greater control over facility siting and surface impacts associated with oil and natural gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments can inspect oil and natural gas operations and impose fines for leaks and spills. Regulation in the municipalities and areas where we operate could result in increased costs, delays in securing permits and other approvals related to our operations, and otherwise materially impact our ability to operate and drill new wells in the areas where we hold oil and natural gas interests.

The CECMC has adopted significant additional regulations to implement SB 181. The legislation mandated CECMC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned or shut–in, financial assurance, wellbore integrity, and application fees. In November 2022, the CECMC completed a rulemaking on flowlines and wells that are inactive, temporarily abandoned, or shut–in and completed a rulemaking on wellbore integrity in June 2020. In January 2021, the results of a major rulemaking took effect addressing a wide range of topics, including facility siting, cumulative impacts, development approvals, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection. Those rules apply to permit applications pending on, or submitted after, the date the rule became effective, and generally to operations occurring on or after that date. The CECMC has also issued rules on financial assurance, application fees, and high–priority habitat. The financial assurance rule increased the amounts that operators are required to provide as a surety bond to ensure that wells will be properly plugged and abandoned at the end of their lifecycle. On October 15, 2024, the CECMC adopted new rules regarding the cumulative impacts of oil and natural gas operations, including increased scrutiny on a project’s proximity to other industrial sites, residential and school areas, disproportionately impacted communities, and “cumulatively impacted communities.” The rules set GHG emissions intensity targets for oil and natural gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas. Depending on how these and any other new rules are applied and enforced, they could add substantial increases in well costs for our Colorado operations. The rules could also impact our ability to operate and extend the time necessary to obtain drilling permits, which would create substantial uncertainty about future development plans.

SB 181 also required the CDPHE, in conjunction with the Air Quality Control Commission (“AQCC”), to undertake rulemaking efforts to minimize methane emissions and emissions of other hydrocarbons, volatile organic compounds and nitrogen oxides associated with certain oil and natural gas facilities. The CDPHE and AQCC adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, and for reducing emissions from pneumatic devices. In December 2019, the AQCC also expanded storage tank control and loadout control requirements. The legislation also grants the CDPHE and AQCC regulatory authority over a broad range of oil and natural gas facilities during pre–production activities, drilling, and completion.

For example, when obtaining a permit for new multi–well pads, the State of Colorado Oil and Gas Development Plans (“OGDP”) approval process may be pursued concurrently with the county approval process. Thirty days prior to the initial filing for a permit, we are required to provide notice to relevant local government authorities and proximate local governments and schools within 2,000 feet of our proposed site. Following such notice, a development plan may be filed, subject to potential requests for hearings and consultation, with such process lasting on average between 90 and 150 days. Upon approval by state authorities, a development plan will be subject to a 30–day public comment period (or 45 days in the case of a plan contemplating drilling within 2,000 feet of a disproportionately impacted community), with such period subject to extension at the discretion of state authorities. Upon completion of the public comment period, the CECMC Director will make a recommendation to approve, approve with conditions of approval, or deny the development plan. The CECMC will then hold a hearing to determine whether to approve, deny or stay an application 7 to 14 days after the recommendation of the CECMC Director. If the development plan is approved, drilling on the applicable pad may commence after a 60– to 90–day wellbore permitting administrative process.

Concurrent with the state approval process, the Weld Oil & Gas Location Assessment (“WOGLA”) application for construction of improvements related to oil and gas exploration and production in Weld County, Colorado, will be subject to approval by the Weld County Oil and Gas Energy Department. Prior to the application, a meeting hosted by Weld County will review all alternate locations within the development area attended by all other relevant state and local regulatory agencies. Following the pre–application meeting, a 30–day notice is submitted to Weld County stating a WOGLA application will be filed. Subsequently, a WOGLA application may be filed with a public intervention period occurring 20 days prior to a hearing. The hearing for WOGLA applications is scheduled for a minimum of 45 days from the date of submission. The Weld County hearings officer will hear the WOGLA applications for approval, and upon such approval, an order will be issued and a grading permit application must be filed prior to construction upon location.

As of December 31, 2025, we employed 59 full–time employees. We have never experienced a work stoppage and believe we maintain positive relationships with our employees.

Following the acquisition and development of our existing and future E&P assets, our revenues, profitability, and cash flows will depend upon the prices for oil, natural gas, and NGLs. The prices we may receive for oil, natural gas, and NGLs production are volatile and a decrease in prices can materially and adversely affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness, and to obtain additional capital on attractive terms. Changes in oil, natural gas, and NGLs prices have a significant impact on the amount of oil, natural gas, and NGLs that we can produce economically, the value of our reserves and on our cash flows. Historically, world–wide oil, natural gas, and NGLs prices and markets have been subject to significant change and may continue to change in the future. During the year ended December 31, 2025, the average West Texas Intermediate spot price was $65.38, as compared to an average price of $76.63 for the year ended December 31, 2024. The average Henry Hub natural gas spot price during the year ended December 31, 2025 was $3.52, as compared to an average of $2.19 for the year ended December 31, 2024.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil, natural gas, and NGLs reserves (including “dry holes”). We must incur significant expenditures to drill and complete wells, the costs of which are often uncertain. It is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities. Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third–party operators may be curtailed, delayed or cancelled. The cost of our drilling, completing and operating wells may increase and our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

A failure to recover our investment in any E&P assets, increases in the costs of our drilling operations or those of third–party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third–party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.

We intend to utilize multi–well pad drilling and project development where practical. Project development may involve more than one multi–well pad being drilled and completed at one time in a relatively confined area. Wells drilled on a pad or in a project may not be brought into production until all wells on the pad or project are drilled and completed. Problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi–well pad drilling and project development can cause delays in the scheduled commencement of production, or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing as well as declines in oil and natural gas prices. Further, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi–well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.

Our potential drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional evaluation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. Prior to drilling, the use of 2–D and 3–D seismic technologies, various other technologies, and the study of producing fields in the same area will still not enable us to know conclusively whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. In addition, the use of 2–D or 3–D seismic data and other technologies requires greater pre–drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures which may result in reduction in our returns or increase our losses. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill any dry holes in our current or future drilling locations, our profitability and the value of our properties will likely be reduced. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations, or producing fields will be applicable to our drilling locations. Further initial production rates reported by us or other operators may not be indicative of future or long–term production rates. In sum, the cost of drilling, completing, and operating any well is often uncertain, and new wells may not be productive.

Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. As a result of the uncertainties, estimated quantities of oil, natural gas, and NGLs reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas, and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of non–recovery and estimates of future net cash flows.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the NGA as well as under Section 311 of the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open–access, non–discriminatory basis.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non–discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

We will encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well–established companies that have been engaged in the oil and natural gas business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive oil and natural gas properties and may be able 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 be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favourable terms. These companies may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices, such as the current commodity price environment, and to absorb the burden of current and future governmental regulations and taxation. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

Our exploration, production, and development activities are subject to extensive federal, state, and local government regulations, which may change from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds and other financial assurance, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas from wells below actual production capacity in order to conserve supplies of oil and natural gas. These laws and regulations may affect the costs, manner, and feasibility of our operations by, among other things, requiring us to make significant expenditures in order to comply and restricting the areas available for oil and natural gas production. Failure to comply with these laws and regulations may result in substantial liabilities to third–parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations, could have a material adverse effect on us, such as by imposing, penalties, fines and/or fees, taxes and tariffs on carbon that could have the effect of raising prices to the end user and thereby reducing the demand for our products.

All of our current E&P assets are located in the DJ Basin in Colorado. Because our assets are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including natural disasters, government regulations and midstream interruptions. For example, bottlenecks in processing and transportation have occurred in the past in the Wattenberg Field in the DJ Basin and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of formations exposes us to risks, such as changes in field–wide rules that could adversely affect development activities or production relating to those formations. Such events could have a material adverse effect on our results of operations and financial condition. In addition, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increases as a result of numerous factors including increases in exploration and production activity, supply chain problems, and labor shortages. Any shortages or increased costs could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition, or results of operations.

In addition, seasonal weather conditions and natural disasters could severely disrupt normal operations and harm our business. During periods of heavy snow, ice, wind or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues, or we could suffer weather–related damage to our facilities and equipment, resulting in delays in operations. Our exploration activities may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations.

Our oil, natural gas, and NGLs exploration, production, and development operations are subject to stringent federal, state, local and other applicable laws and regulations governing worker health and safety, the release or disposal of materials into the environment or otherwise relating to environmental protection. Numerous governmental entities, including the EPA, the U.S. Occupational Safety and Health Administration, and analogous state agencies, including the CDPHE and the CECMC, have the power to enforce compliance with these laws and regulations. These laws and regulations may, among other things, require the acquisition of permits to conduct drilling; govern the amounts and types of substances that may be released into the environment; limit or prohibit construction or drilling activities in environmentally–sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions; impose obligations to reclaim and abandon well sites and pits; impose seasonal limitations on our ability to conduct operations due to wildlife migration patterns or other similar concerns; and impose specific criteria addressing worker protection. Compliance with such laws and regulations may impact our operations and production, require us to install new or modified emission controls on equipment or processes, incur longer permitting timelines, restrict the areas in which some or all operational activities may be conducted, and incur significantly increased capital or operating expenditures, which costs may be significant. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

Additionally, certain environmental laws impose strict, joint and several liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released. Failure to comply with these laws and regulations may also result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas. Moreover, accidental spills or other releases may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such spills or releases, including any third–party claims for damage to property, natural resources or persons. We may not be able to fully recover such costs from insurance. One or more of these developments that impact us, our service providers or our customers could have a material adverse effect on our business, results of operations and financial condition and reduce demand for our products.

Certain interest groups generally opposed to the development of oil and natural gas, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing the development of oil and natural gas. For example, following the failure of several ballot initiatives to restrict oil and natural gas development, Colorado passed a law in April 2019 (Senate Bill 19–181) that, among other things, changes the mission of the CECMC from fostering oil and natural gas development to instead focus on environmental protection, directs the CECMC and various other state agencies to consider new rules imposing stricter environmental controls on the oil and natural gas industry, and provides local governments with the authority to promulgate their own regulations on oil and natural gas development. Pursuant to this statutory change, the CECMC has issued new rules relating to the agency’s new mission—formerly “fostering” oil and natural gas development, now “regulating” it—including, among other things, increasing oil and natural gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibiting routine venting and flaring, and increasing wildlife protections. Additional rules will also address cumulative impacts through a new state regulatory program and will completely revise state permitting procedures. In May 2023, Colorado passed a law (House Bill 23–1294) that requires the CECMC to promulgate rules addressing cumulative impacts of oil and natural gas operations by April 28, 2024. CECMC adopted new cumulative impact rules on October 15, 2024. These rules require regulators to consider cumulative impacts of oil and natural gas operations in permitting decisions and increase scrutiny on the project’s proximity to other industrial sites, residential areas and school areas, disproportionately impacted communities, and “cumulatively impacted communities.” The rules also set GHG emissions intensity targets for oil and natural gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas. While the ultimate impact of the new Colorado laws and related rules is currently unknown, these laws or passage or enactment of other similar legislation could have a material adverse effect on our operations in Colorado.

Also at the federal level, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, and impose standards reducing methane emissions from oil and natural gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. 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. Under the final rules, states had two years to prepare and submit their plans to impose methane emission controls on existing sources, but in July 2025, the EPA extended its deadline to January 2027. The presumptive standards established under the final rules are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero–emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to the EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial.

In addition, the U.S. Congress may continue to consider and pass legislation related to the reduction of GHG emissions, including methane and carbon dioxide. For example, the IRA, which appropriates significant federal funding for renewable energy initiatives and was signed into law in August 2022. The methane emissions charge would have started at $900 per ton of methane emitted in calendar year 2024, increase to $1,200 for emissions in 2025, and be set at $1,500 for 2026 and each year after. In January 2024, the EPA issued a proposed rule to implement the waste emissions charge with a proposed effective date in 2025 for reporting year 2024 emissions. However, in early 2025 Congress used the Congressional Review Act to void the implementing rule. A future Congress could implement a similar methane charge and incentives for renewable energy infrastructure development could impose additional costs on our operations and further accelerate the transition of the economy away from the use of oil and natural gas towards lower– or zero–carbon emissions alternatives. Furthermore, on March 6, 2024, the SEC finalized a rule requiring the reporting of climate–related risks and financial impacts, as well as GHG emissions for larger companies. Compliance dates under the final rule were to be phased in by registrant category with some filers required to incorporate the disclosures in fiscal year 2025 filings. However, the rule was challenged and, in March of 2025, the SEC voted to withdraw its defense of the new disclosure rules. The rules have not been rescinded, although the U.S. Court of Appeals for the Eighth Circuit has ordered that the litigation be held in abeyance until such time as the SEC either reconsiders the rules or resumes its defense of the rules.

States have also implemented or are considering implementing laws and regulations that would require climate–related disclosures, which could result in additional costs to comply with disclosure requirements as well as increase costs of and restrictions on access to capital. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to alleged climate–related damages resulting from our operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions. From time to time, the SEC has also focused additional scrutiny on existing climate–change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures were misleading or deficient. These ongoing regulatory actions and the emissions fee and funding provisions of the IRA could increase operating costs within the oil and natural gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.

At the international level, the United Nations–sponsored Paris Agreement, though non–binding, calls for signatory nations to limit their GHG emissions through individually–determined reduction goals every five years after 2020. Moreover, the international community convenes annually at the Conference of the Parties to negotiate further pledges and initiatives, such as the Global Methane Pledge (a collective goal to reduce global methane emissions by 30 percent from 2020 levels by 2030). Although in January of 2025 President Trump again ordered the withdrawal of the U.S. from the Paris Agreement, a future President may choose to rejoin. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfil the U.S.’ commitments under the Paris Agreement or other international agreements cannot be predicted at this time. In December 2023, at the 28th Conference of the Parties, the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity, though no timeline for doing so was set. While non–binding, the agreements coming out of these conferences could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for, and increase potential opposition to, the exploration and production of fossil fuels.

There are also increasing financial risks for oil and natural gas producers as certain shareholders, bondholders and lenders 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 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 be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. Additionally, there is also the possibility that financial institutions will be pressured or required to adopt policies that limit funding for fossil fuel energy companies. For example, in 2021 the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub–alliances of GFANZ generally require participants to set short–term, sector–specific targets to transition their financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate–related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network for Greening the Financial System to identify key issues and potential solutions for the climate–related challenges most relevant to central banks and supervisory authorities. In September 2022, the Federal Reserve announced that six of the largest U.S. largest banks will participate in a pilot climate scenario analysis exercise, which took place throughout 2023, to enhance the ability of firms and supervisors to measure and manage climate–related financial risk. While we cannot predict what policies may result from these developments, such efforts could make it more difficult to secure funding for exploration and production business activities on favourable terms, or at all. 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 natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Any material reduction in the capital available to us or our fossil fuel–related customers could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could reduce the demand for our products and services.

Businesses across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. Businesses that are perceived to be operating in contrast to investor or stakeholder expectations and standards, which are continuing to evolve, or businesses that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such business entity could be materially and adversely affected. Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG–related disclosures, increasing mandatory ESG disclosures, and consumer demand for alternative forms of energy may result in increased operating and compliance costs, reduced demand for our products, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, reputational damage, and negative impacts on our access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that we could be subject to additional governmental investigations, private litigation or activist campaigns as stockholders may attempt to effect changes to our business or governance practices.

While we may elect to seek out various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including as a result of unforeseen costs or technical difficulties associated with achieving such results. Similarly, while we may decide to participate in various voluntary ESG frameworks and certification programs, such participation may not have the intended results on our ESG profile. In addition, voluntary disclosures regarding ESG matters, as well as any ESG disclosures currently required or required in the future, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. Moreover, failure or a perception of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us, and negatively impact our operations and goodwill. Notwithstanding our election to pursue aspirational ESG–related targets in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG–related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs, technical or operational obstacles or other market or technological developments beyond our control.

Our operations require water for our planned oil and natural gas exploration during drilling and completion activities. Our access to water may be limited due to reasons such as prolonged drought, private third–party competition for water in localized areas or our inability to acquire or maintain water sourcing permits or other rights as well as governmental regulations or restrictions adopted in the future. For example, in 2023, the Governor of Colorado signed into law HB 23–1242 which places restrictions on the use of fresh water for oil and natural gas operations and requires oil and natural gas operators to report their water use. Any difficulty or restriction on locating or contractually acquiring sufficient amounts of water in an economical manner could adversely impact our planned operations.

In recent years, wells used for the disposal by injection of flowback water or certain other oilfield fluids below ground into non–producing formations have been associated with an increased number of seismic events, with research suggesting that the link between seismic events and wastewater disposal may vary by region and local geology. The U.S. geological survey has identified Colorado as one of six states with the most significant hazards from induced seismicity. Concerns by the public and governmental authorities have prompted several state agencies to require operators to take certain prescriptive actions or limit disposal volumes following unusual seismic activity. The CECMC requires operators to monitor and evaluate for seismicity risks in certain situations. Other states have from time–to–time suspended disposal well permits or otherwise restricted activity in certain areas in response to seismic activity. For example, in both New Mexico and Texas, state regulatory agencies have implemented seismicity response programs that have resulted in state regulators suspending or curtailing disposal well injection operations and imposing additional seismic monitoring and reporting requirements on disposal well operators. Restrictions on produced water disposal well injection activities or suspensions of such activities, whether due to the occurrence of seismic events or other regulatory actions could increase our costs to dispose of produced water and adversely impact our results of operations.

Historically, we have relied upon cash from financing activities to fund substantially all of the cash requirements of our activities and have incurred significant losses and experienced negative cash flow. For the years ended December 31, 2025 and 2024, we incurred a net loss attributable to Prairie Operating Co. common stockholders of $60.9 million and $40.9 million, respectively, and had an accumulated deficit of $87.7 million and $119.8 million as of December 31, 2025 and 2024, respectively. We may continue to incur losses for an indeterminate period of time and may be unable to sustain profitability. An extended period of losses and negative cash flow may prevent us from successfully operating and expanding our business. We may be unable to sustain or increase our profitability on a quarterly or annual basis. Refer to Part II. Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.

Our ability to obtain external financing in the future may be subject to a variety of uncertainties, including our future financial condition, results of operations, cash flows and the liquidity of international capital and lending markets. We may need to undertake equity, equity–linked or debt financings to secure additional funds. If we raise additional funds through future issuances of equity or convertible debt securities, our existing stockholders could suffer significant dilution, and any new equity securities we issue could have rights, preferences and privileges superior to those of holders of our Common Stock. Any debt financing that we secure in the future could involve restrictive covenants relating to our capital raising activities and other financial and operational matters, including the ability to pay dividends. This may make it more difficult for us to obtain additional capital and to pursue business opportunities. A large amount of bank borrowings and other debt may result in a significant increase in interest expense while at the same time exposing the Company to increased interest rate risks. Refer to Part II. Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.

For example, on March 3, 2026, we announced the voluntary resignation of our Chief Executive Officer and Chairman, Edward Kovalik, and the retirement of our President and Director, Gary C. Hanna. Our Board of Directors has appointed Richard N. Frommer, a member of the Board of Directors, to serve as Interim President and Chief Executive Officer of the Company, while we conduct a search for a permanent President and Chief Executive Officer. Additionally, the Board of Directors has also appointed Erik Thoresen to serve as Chairman of the Board. The timeline for identifying, retaining and integrating a permanent President and Chief Executive Officer is currently unknown. Any failure to timely identify and hire a permanent President or Chief Executive Officer and successfully integrate and transition such persons into their new roles within our Company could adversely impact our ability to achieve our long–term financial, operating or strategic objectives. Such leadership changes may be difficult to management and may result in additional costs and uncertainty concerning our future direction.

The loss of any key personnel would require the remaining key personnel to divert immediate attention to seeking a replacement. Competition for senior management personnel is intense, and our inability to find a suitable replacement for any departing key personnel on a timely basis could adversely affect our ability to operate and grow our business.

If any of our current or future business partners or contracting counterparties fails to perform or terminates their agreement(s) with us for any reason, or if our current or future business partners or contracting counterparties with which we have short–term agreements refuse to extend or renew the agreement or enter into a similar agreement, our ability to carry on operations may be impaired. In addition, we will depend on the continued operation of long–term business partners and contracting counterparties and on maintaining good relations with them. If one of our future long–term partners or counterparties is unable (including as a result of bankruptcy or a liquidation proceeding) or unwilling to continue operating in the line of business that is the subject of our contract, we may not be able to obtain similar relationships and agreements on terms acceptable to us or at all. If a current or future partner or counterparty fails to perform or terminates any of the agreements with us or discontinues operations, and we are unable to obtain similar relationships or agreements, such events could have an adverse effect on our operating results and financial condition.

Our information and operational technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may become the target of cyberattacks or information security breaches that result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or adversely disrupt our business operations. Advances in computer capabilities, discoveries in the field of artificial intelligence, cryptography, or other developments may result in a compromise or breach of the technology we use to safeguard confidential, personal, or otherwise protected information. As cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. A cyberattack or security breach could result in liability resulting from data privacy or cybersecurity claims, liability under data privacy laws, regulatory penalties, damage to our reputation, long–lasting loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition, or results of operations. To date, we have not experienced any material losses relating to cyberattacks; however, there can be no assurance that we will not suffer such losses in the future. No security measure is infallible. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

We produce our financial statements in accordance with GAAP. Effective internal controls are necessary for us to provide reliable financial reports to help mitigate the risk of fraud and to operate successfully as a publicly traded company. As a public company, we are required to document and test our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes–Oxley Act of 2002, or Section 404. Further, Section 404 requires annual management assessments of the effectiveness of our internal controls over financial reporting. Testing and maintaining internal controls can divert our management’s attention from other matters that are important to our business. We may not be able to conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404. If we are unable to conclude that we have effective internal controls over financial reporting, investors could lose confidence in our reported financial information and our company, which could result in a decline in the market price of our Common Stock, and cause us to fail to meet our reporting obligations in the future, which in turn could impact our ability to raise additional financing if needed in the future.

As a public company, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes–Oxley Act of 2002, related regulations of the SEC and the requirements of Nasdaq. Complying with these statutes, regulations and requirements occupy a significant amount of time of our Board of Directors and management and significantly increase our costs and expenses. We are required to:

We are a “smaller reporting company” as defined under the Securities Act and Exchange Act and expect to remain a “smaller reporting company” for the foreseeable future. We are therefore entitled to rely on certain reduced disclosure requirements, such as the ability to present only the two most recent fiscal years of audited financial statements in our Annual Report on Form 10–K and reduced disclosure obligations regarding executive compensation. Additionally, as a “non–accelerated filer”, we currently are not required to obtain an attestation report on internal control over financial reporting issued by our independent registered public accounting firm.

We currently have U.S. federal and state net operating loss (“NOL”) carryforwards. Our ability to use these tax attributes to reduce our future U.S. federal and state income tax obligations depends on many factors, including our future taxable income, which cannot be assured. In addition, our ability to use NOL carryforwards and other tax attributes are subject to significant limitations under Section 382 and Section 383 of the Internal Revenue Code of 1986, as amended (the “Code”). Under those sections of the Code, if a corporation undergoes an “ownership change” (as defined in the Code), the corporation’s ability to use its pre–change NOL carryforwards and other tax attributes may be substantially limited.

Determining the limitations under Section 382 of the Code is technical and complex. A corporation generally will experience an ownership change if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three–year period. We may in the future undergo an ownership change under Section 382 of the Code. If an ownership change occurs, our ability to use our NOL carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations may be materially limited, which could adversely affect our cash flows.

Additionally, in 2023 Narrogal Nominees Pty Ltd ATF Gregory K O’Neill Family Trust (the “O’Neill Trust received Series A warrants (“Series E A Warrants”) to purchase 4,000,000 shares of Common Stock.

Additionally, in March 2025, we issued 148,250 shares of Series F Convertible Preferred Stock, $0.01 par value per share (“Series F Preferred Stock”) to an investor (the “Series F Preferred Stockholder”) for aggregate consideration of approximately $148.3 million, which is convertible into shares of Common Stock, and we agreed to issue to the Series F Preferred Stockholder, subject to the satisfaction of certain conditions, a warrant to purchase additional shares of Common Stock (“Series F Preferred Stock Warrants”) (collectively, the “Series F Preferred Offering”). On March 25, 2026, we and the Series F Preferred Stockholder entered into an Amendment to the Securities Purchase Agreement and Form of Anniversary Warrant (the “Series F Preferred Stock Warrant Amendment”), which, among other things, changes the issuance date of the Series F Preferred Stock Warrants from the first anniversary of the issuance date of the Series F Preferred Stock to April 7, 2026.

In addition, sales of a substantial number of shares of Common Stock issued upon the conversion or exercise, as applicable, of the outstanding Series D Preferred Stock, Series F Preferred Stock, Series D PIPE Warrants, Series E A Warrants, Exok Warrants, Subordinated Note Warrants, Merger Options, and, if issued, the Series F Preferred Stock Warrants, or even the perception that such sales could occur, could adversely affect the market price of our Common Stock. The conversion or exercise of such securities could result in dilution in the interests of our other stockholders and adversely affect the market price of our Common Stock.

Since the stock price of our Common Stock has fluctuated in the past, has been recently volatile and may be volatile in the future, investors in our Common Stock could incur substantial losses. In the past, following periods of volatility in the market, securities class–action litigation has often been instituted against companies. Such litigation, if instituted against us, could result in substantial costs and diversion of management’s attention and resources, which could materially and adversely affect our business, financial condition, results of operations and growth prospects. There can be no guarantee that our stock price will remain at current levels or of the price at which our Common Stock may be sold in the future.

The market price of our Common Stock is likely to be influenced by the Series F Preferred Stock. For example, the market price of our Common Stock could become more volatile and could be depressed by investors’ anticipation of the potential resale in the market of a substantial number of additional shares of Common Stock received upon conversion of, or as a dividend on, the Series F Preferred Stock or, if issued, upon exercise of the Series F Preferred Stock Warrants, which will be issuable to the holders of our Series F Preferred Stock if, on April 7, 2026 the Series F Preferred is outstanding and the per share trading price of the Common Stock is less than 115% of the conversion price of the Series F Preferred Stock, as described in the Series F Certificate of Designation and as amended in the Series F Preferred Stock Warrant Amendment. Investors may also sell their shares of Common Stock as a result of the issuance of the Series F Preferred Stock, which is a senior security to our Common Stock.

Our Common Stock ranks junior to our outstanding preferred stock, including the Series F Preferred Stock, with respect to the payment of dividends and amounts payable in the event of our liquidation, dissolution or winding–up of our affairs. This means that, in the event of our voluntary or involuntary liquidation, dissolution or winding–up of our affairs, no distribution of our assets may be made to holder(s) of our Common Stock until we have paid to holders of our outstanding preferred stock, including the Series F Preferred Stock, the applicable liquidation preference, which, with respect to our Series F Preferred Stock, is equal to the Fundamental Change Redemption Price (as defined in the Series F Certificate of Designation) per share. Likewise, unless accumulated dividends have been paid on our outstanding preferred stock, including all of our Series F Preferred Stock, through the most recently completed dividend period, no dividends may be declared or paid on our Common Stock and we will not be permitted to repurchase any shares of our Common Stock, subject to limited exceptions.

We are entitled under our Charter to issue up to 500,000,000 shares of Common Stock and 50,000,000 shares of preferred stock, although these amounts may change in the future subject to stockholder approval. Our Board of Directors has broad authority to determine voting, dividend, conversion and other rights of any shares of preferred stock, subject to the terms of any then–existing shares of preferred stock, our Credit Facility and applicable law. In addition, during June of 2025, we entered into an equity distribution agreement, whereby we may sell from time to time at prevailing market prices, at our option, shares of our Common Stock up to an aggregate offering price of $75,000,000. Any additional stock issuances could be made at a price that reflects a discount or premium to the then–current market price of our Common Stock. In addition, in order to raise capital, we may need to issue securities that are convertible into or exchangeable for a significant amount of our Common Stock. Our Board of Directors may generally issue those shares of Common Stock and preferred stock, or convertible securities to purchase those shares, without further approval by our common stockholders. Any preferred stock we may issue could have such rights, preferences, privileges and restrictions as may be designated from time–to–time by our Board of Directors, including preferential dividend rights, voting rights, conversion rights, redemption rights and liquidation provisions. We may also issue additional securities to our directors, officers, employees and consultants as compensatory grants in connection with their services, both in the form of stand–alone grants or under our stock incentive plans. The issuance of additional securities may cause substantial dilution to our stockholders.

We are an independent oil and gas company focused on the acquisition and development of crude oil, natural gas, and NGLs. Our assets and operations are strategically located in the oil region of rural Weld County, Colorado, within the DJ Basin. We believe the DJ Basin to be one of the premier resource plays in the U.S., as Weld County boasts some of the lowest break–even prices in the U.S., and has a long production history which has proven and consistent results. The productivity of this resource is demonstrated by the integral role that Weld County holds in Colorado’s energy economy, having produced approximately 83% of Colorado’s oil production to date.

As of December 31, 2025, our assets included approximately 68,000 net leasehold acres in, on and under approximately 98,200 gross acres. We strive to deliver energy in an environmentally efficient manner by deploying next–generation technology and techniques. In addition to growing production through our drilling operations, we intend to continue growing our business through accretive acquisitions, such as the NRO Acquisition, which closed in October 2024, the Bayswater Acquisition, which closed in March 2025, the Edge Acquisition, which closed in July 2025, and the Summit and Crown acquisitions, which closed in October 2025, focusing on assets with the following criteria: (i) producing reserves, with opportunities to add accretive, undeveloped bolt–on acreage; (ii) ample, high rate–of–return inventory of drilling locations that can be developed with cash flow reinvestment; (iii) strong well–level economics; (iv) liquids–rich assets; and (v) accretive valuation.

On February 6, 2025, we and certain of our subsidiaries entered into a purchase and sale agreement with Bayswater, pursuant to which we and certain of our subsidiaries agreed to acquire the Bayswater Assets from Bayswater for a purchase price of $602.8 million, subject to certain closing price adjustments.

On March 26, 2025, we entered into our Credit Facility, which amended and restated our existing reserve–based credit agreement with Citi. The Credit Facility provides for a maximum credit commitment of $1.0 billion and is scheduled to mature on March 26, 2029. Further, on March 26, 2025, we issued Common Stock in a public offering, resulting in proceeds of $41.4 million, net of $2.4 million of underwriting discounts and commissions and $3.7 million in issuance fees. Concurrently with the public offering, we issued the Series F Preferred Stock, resulting in approximately $136.1 million of net proceeds, after deducting the advisor fees and offering expenses.

At the closing of the Bayswater Acquisition on March 26, 2025, we (i) paid approximately $482.5 million in cash to Bayswater, $15.0 million of which was deposited in escrow pending the Additional Working Interest Acquisition, which Bayswater acquired and assigned to us on April 11, 2025, and (ii) issued 3,656,099 shares of our Common Stock to Bayswater. We funded the cash portion of the purchase price for the Bayswater Acquisition with cash on hand, the proceeds from the issuance of Common Stock and the issuance of the Series F Preferred Stock, and borrowings under our Credit Facility. We completed the final settlement with Bayswater on October 15, 2025, resulting in a final consideration of $475.6 million. Refer to Liquidity and Capital Resources – Significant Sources of Liquidity below for a further discussion of issuance of the Series F Preferred Stock and Credit Facility.

On April 1, 2025, we launched the development program at our Rusch pad development in Weld County, which consists of 11 two–mile lateral wells. The Rusch wells came online late in September 2025 with initial production measured before any deductions for fuel, flare, or vented volumes (“Two–stream”) gross production per well of 475 Boe/d.

On April 28, 2025, we announced our plan to begin completions on nine previously drilled but uncompleted wells acquired in the Bayswater Acquisition. Completion activities at the Opal/Coalbank pad began in May 2025, and the wells came online mid–July 2025 with initial average Two–stream gross production per well of 725 Boe/d.

On June 1, 2025, we moved the drilling rig to our Noble pad development in Weld County, which consists of seven wells. The Noble wells came online in November 2025 with initial average Two–stream gross production per well of 550 Boe/d.

In September 2025, we moved the drilling rig to our then–recently acquired Simpson pad development in Weld County, which consists of six wells. Three of the Simpson pad wells came online in December 2025 and the remainder came online in January 2026 with initial average Two–stream gross production per well of 500 Boe/d.

In December 2025, we moved the drilling rig to our Blehm pad and then our Schneider pad, both of which are in Weld County and consist of five wells each. Completion activities at the Blehm and Schneider pads are ongoing and first production is expected early in the second quarter of 2026. At the end of 2025, we moved the drilling rig to our Elder East and West pad, which consists of nine wells. Drilling at the Elder East and West pad is expected to be completed early in the second quarter of 2026.

On June 20, 2025, we entered into an Equity Distribution Agreement (the “Equity Distribution Agreement”) with Citigroup Global Markets Inc. and Truist Securities, Inc., as managers (together, the “Managers”). Pursuant to the agreement, we have the option to sell shares of Common Stock up to an aggregate offering price of $75.0 million through the Managers (the “ATM Offering”). The Common Stock sold under the ATM Offering, if any, will be made under our Registration Statement on Form S–3, which was declared effective on May 2, 2025, and the prospectus supplement dated June 20, 2025 relating to the ATM Offering filed with the SEC, in each case, as may be amended or supplemented from time to time.

We anticipate the net proceeds from the ATM Offering will be used for general corporate purposes, which may include, among other things, advancing our development and drilling program, repayment of existing indebtedness, or financing potential acquisition opportunities. Additionally, per the Series F Certificate of Designation, the Series F Preferred Stockholder can require us to use a portion of the net proceeds from sales of the ATM Offering to redeem a number of shares of the Series F Preferred Stock. As of December 31, 2025, we have not issued any shares under the ATM Offering.

Abandonment and impairment of unproved properties. For the year ended December 31, 2025, we recorded $3.4 million of abandonment and impairment related to unproved properties, which reflects unproved locations that we have deemed non–core and allowed to expire. We did not record any abandonment and impairment related to unproved properties for the year ended December 31, 2024.

Interest expense. For the year ended December 31, 2025, interest expense increased $27.4 million compared to the year ended December 31, 2024, primarily driven by interest on the Credit Facility, the outstanding borrowing of which increased to fund the Bayswater Acquisition in March 2025. Refer to Liquidity and Capital Resources – Significant Sources of Liquidity below for a further discussion of the Credit Facility.

Loss on adjustment to fair value – embedded derivatives, debt, and warrants. We have several financial instruments that are or were previously valued at fair value on a recurring basis; therefore, we recognize the changes in fair value at each remeasurement period as a loss on adjustment to fair value – embedded derivatives, debt, and warrants on our consolidated statements of operations for the period. For the year ended December 31, 2025, the loss on adjustment to fair value – embedded derivatives, debt, and warrants reflects losses on fair value of $68.0 million for the Series F Preferred Stock Warrants, $5.5 million for the Senior Convertible Note, and $0.1 million for the subordinated promissory note (the “Subordinated Note”) held by First Idea Ventures LLC and The Hideaway Entertainment LLC (together, the “Noteholders”), which were partially offset by gains on fair value of $9.6 million for the Series F Preferred embedded derivatives, $3.9 million for the warrants issued by the Company to the Noteholders (the “Subordinated Note Warrants”), and $0.8 million for the Standby Equity Purchase Agreement (the “SEPA”) recognized during the period. For the year ended December 31, 2024, the loss on adjustment to fair value – debt and warrants reflects the fair value adjustments of $0.8 million for the SEPA, $2.1 million for the Senior Convertible Note, $1.1 million for the Subordinated Note, and $1.4 million for the Subordinated Note Warrants recognized during the period. Refer to Liquidity and Capital Resources – Significant Sources of Liquidity below for a further discussion of the SEPA, the Senior Convertible Note, the Subordinated Note, the Series F Preferred Stock embedded derivatives, and the Series F Preferred Stock Warrants.

Loss on debt issuance. At the time of issuance, we elected the fair value option to account for both the Subordinated Note and the Subordinated Note Warrants and engaged a third–party valuation expert to assist in preparing the fair value of both instruments at issuance. As of December 31, 2024, the total fair value of the Subordinated Note and the Subordinated Note Warrants exceeded the proceeds of $5.0 million, as a result, we have recognized a loss on debt issuance of $3.0 million on our consolidated statements of operations for the year ended December 31, 2024. We did not recognize a loss on debt issuance during the year ended December 31, 2025.

Adjusted EBITDA is derived from net income (loss) from continuing operations and is adjusted for income tax expense, depreciation, depletion, and amortization, accretion of asset retirement obligations, abandonment and impairment of unproved properties, non–cash stock–based compensation, interest expense, net, non–cash loss on adjustment to fair value – embedded derivatives, debt, and warrants, loss on debt issuance, unrealized gain on derivatives, and litigation settlement expense, all as applicable. We adjust net income (loss) from continuing operations for the items listed above to arrive at Adjusted EBITDA because these amounts can vary substantially between periods and companies within our industry depending upon accounting methods, book values of assets, capital structures, and the method by which assets were acquired. Adjusted EBITDA has limitations as an analytical tool, including that it excludes certain items that affect our reported financial results. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income calculated in accordance with GAAP or as an indicator of our operating performance or liquidity. Additionally, our calculation of Adjusted EBITDA may not be comparable to similarly titled measures used by other companies.

Our E&P activities will require us to make significant operating and capital expenditures. In 2024, our primary sources of liquidity were proceeds from the issuances of Common Stock, the Senior Convertible Note, and the Subordinated Note, which were primarily used to fund the NRO Acquisition in October 2024. Additionally, in December 2024, our Form S–3 registration statement became effective, and we entered into a reserve–based Credit Facility with Citi. Early in 2025, we amended and restated our existing reserve–based credit agreement with Citi, which now has a maximum credit commitment of $1.0 billion and is scheduled to mature on March 26, 2029. Further, in March 2025, we issued Common Stock in a public offering, resulting in proceeds of $41.4 million, net of $2.4 million of underwriting discounts and commissions and $3.7 million in issuance fees. Concurrently with the public offering, we issued the Series F Preferred Stock, resulting in approximately $136.1 million of net proceeds, after deducting the advisor fees and offering expenses. We used cash on hand, the proceeds from the Common Stock and Series F Preferred Stock issuances, and borrowings under the Credit Facility to close the Bayswater Acquisition on March 26, 2025. At the closing of the Bayswater Acquisition, we paid Bayswater approximately $482.5 million in cash, $15.0 million of which was deposited in escrow pending the Additional Working Interest Acquisition, which Bayswater acquired and assigned to us on April 11, 2025, and issued 3,656,099 shares of Common Stock to Bayswater.

Additionally, on June 20, 2025, we entered into the ATM Offering, which allows us to sell shares of our Common Stock up to an aggregate offering price of $75.0 million through the Managers. Sales of the shares of Common Stock sold under the ATM Offering, if any, will be made under our Registration Statement on Form S–3, which was declared effective by the SEC on May 2, 2025, and the prospectus supplement dated June 20, 2025 relating to the ATM Offering filed with the SEC, in each case, as may be amended or supplemented from time to time. As of December 31, 2025, we have not issued any shares under the ATM Offering.

Management expects that our cash balance, expected revenues from the producing Bayswater wells, and liquidity available under the Credit Facility, proceeds from the ATM Offering, and potential offerings under our effective Form S–3 registration statement will be sufficient to fund our development program and operations.

We are subject to certain financial covenants and customary restrictive covenants under the Credit Facility. The financial covenants require us to maintain, for each fiscal quarter commencing with the fiscal quarter ending March 31, 2025, a Net Leverage Ratio (as defined in the Credit Facility agreement) of no greater than 3.00 to 1.00 and a Current Ratio (as defined in the Credit Facility agreement) of at least 1.00 to 1.00. As of December 31, 2025, we are in compliance with all covenants under the Credit Facility.

As of December 31, 2025 and 2024, we had $366.0 million and $28.0 million, respectively, of revolving borrowings and no letters of credit outstanding under the Credit Facility, resulting in $109.0 million and $7.2 million, respectively, of availability for future borrowings and letters of credit. Additionally, as of December 31, 2025 and 2024, we had $12.6 million and $1.7 million, respectively, of unamortized deferred financing costs associated with our Credit Facility, which are presented as debt issuance costs, net on the consolidated balance sheets. These costs will be amortized to interest expense on the accompanying consolidated statements of operations on a straight–line basis over the life of the Credit Facility.

As of December 31, 2025 and 2024, we had $366.0 million and $28.0 million, respectively, of revolving borrowings and no letters of credit outstanding under the Credit Facility, resulting in $109.0 million and $7.2 million, respectively, of availability for future borrowings and letters of credit. Additionally, as of December 31, 2025 and 2024, we had $12.6 million and $1.7 million, respectively, of unamortized deferred financing costs associated with our Credit Facility, which are presented as debt issuance costs, net on the consolidated balance sheets. These costs will be amortized to interest expense on the accompanying consolidated statements of operations on a straight–line basis over the life of the Credit Facility.

We have determined that the SEPA represents a derivative instrument pursuant to ASC Topic 815, Derivatives and Hedging (“ASC 815”), which should be recorded at fair value at inception and remeasured at fair value each reporting period with changes in the fair value recognized in earnings. As of December 31, 2024, we had recorded the SEPA at its fair value of $0.8 million and recorded the corresponding $0.8 million change in fair value as a component of loss on adjustment to fair value – embedded derivatives, debt, and warrants on our consolidated statement of operations for the year ended December 31, 2024. Since we cannot request an Advance Notice on the SEPA while the Series F Preferred Stock is outstanding, we have determined that the fair value of the SEPA as of December 31, 2025 is $0 million, resulting in a gain of $0.8 million, which is presented as part of  loss on adjustment to fair value – embedded derivatives, debt, and warrants on our consolidated statement of operations for the year ended December 31, 2025.

Subordinated Promissory Note and Subordinated Note Warrants. On September 30, 2024, we entered into the Subordinated Note with the Noteholders in a principal amount of $5.0 million, which has a maturity date of March 17, 2027. The Noteholders are entities controlled by Jonathan H. Gray, who is a director of the Company, therefore the Subordinated Note and Subordinated Note Warrants are presented as related–party on our consolidated balance sheets as of December 31, 2025 and 2024. The Subordinated Note has an interest rate of 10.00% and the Noteholders are entitled to a minimum return on capital of up to 2.0x upon the repayment, prepayment or acceleration of the obligations, or the occurrence of certain other triggering events under the Subordinated Note. In December 2024, we made a $1.8 million payment on the Subordinated Note, resulting in a principal balance of $3.2 million as of December 31, 2024.

We have determined that the Series F Preferred Stock should be classified as mezzanine equity because it is currently redeemable at the Series F Preferred Stockholder’s option. Additionally, we determined that certain features of the Series F Preferred Stock require bifurcation and separate accounting as embedded derivatives and that the Series F Preferred Stock Warrants should be accounted for as liabilities because they are not considered indexed to our stock since the potential number of common shares to be issued upon the exercise of such warrants will vary based on the amount of Series F Preferred Stock outstanding on April 7, 2026. On the date of issuance, in accordance with ASC 815, we recorded a liability of $25.5 million for the fair value of the Series F Preferred Stock embedded derivatives and a liability of $22.1 million for the fair value of the Series F Preferred Stock Warrants. As a result, on March 26, 2025, we recognized the Series F Preferred Stock in mezzanine equity based on its relative fair value of $92.6 million, after allocating $47.6 million of the proceeds to the embedded derivative features and the Series F Preferred Stock Warrants. Additionally, we recorded issuance costs of $12.2 million as a reduction to the allocated proceeds.

As of December 31, 2025, in accordance with ASC Topic 480, Distinguishing Liabilities from Equity, we adjusted the value of the Series F Preferred Stock to reflect its maximum redemption amount of $136.1 million, resulting in a remeasurement of Series F Preferred Stock of $80.5 million, which is presented in the remeasurement of Series F Preferred Stock line item on the consolidated statement of operations for the year ended December 31, 2025. Additionally, at each conversion, we reduce the balance of the Series F Preferred Stock by the carrying value of the converted shares, which, as of December 31, 2025, has resulted in a decrease of $34.0 million since the issuance date.

At–the–Market Sales Agreement. On June 20, 2025, we entered into the Equity Distribution Agreement with the Managers. Pursuant to the Equity Distribution Agreement, we have the option to sell shares of our Common Stock up to an aggregate offering price of $75.0 million through the Managers. All Common Stock sold under the Equity Distribution Agreement, if any, will be made under our Registration Statement on Form S–3, which was declared effective on May 2, 2025, and the prospectus supplement dated June 20, 2025 relating to the ATM Offering filed with the SEC, in each case, as may be amended or supplemented from time to time.

The assessment of liquidity requires management to make estimates of future activity and judgments about whether we can meet our obligations, have adequate liquidity to operate, and maintain compliance with the applicable financial covenants of our Credit Facility, as discussed above. Significant assumptions used in our forecasted model of liquidity in the next 12 months include our current cash position and our ability to manage spending. Based on an assessment of these factors, management expects that our cash balance, expected revenues from our existing producing wells, and liquidity available under the Credit Facility, proceeds from the ATM Offering, and potential offerings under our effective Form S–3 registration statement will be sufficient to meet our obligations over the next 12 months and fulfil the financial covenant requirements under our Credit Facility.

As discussed above, following our Form S–3 registration statement becoming effective in December 2024, the entry into our Credit Facility in March 2025, which increased the borrowing base to $475.0 million, and the launch of the ATM Offering in June 2025, we have the ability to access funds through various sources to meet our working capital needs. Our ability to borrow under our Credit Facility does not require action on the part of management, other than requesting the borrowing. As of December 31, 2025, we have availability of $109.0 million under the Credit Facility, which is more or equal to our liquidity needs; therefore, substantial doubt about our ability to continue as a going concern does not exist.

Proved properties. We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, development drilling and completion costs are capitalized when incurred and depleted using the unit–of–production (“UOP”) method based on total estimated proved developed oil and natural gas reserves. The costs of acquiring proved properties are also capitalized and depleted, including leasehold acquisition costs transferred from unproved properties, using the UOP method based on total estimated proved developed and undeveloped reserves. Development drilling and completion costs for wells in–progress are excluded from depletion until the related project is completed and proved producing reserves are established. Exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred.

Crude oil and natural gas reserves. The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. The process of estimating and evaluating crude oil and natural gas reserves is subjective and cannot be measured in an exact manner. As such, management has engaged CG&A, an independent Petroleum Reserve Evaluation Firm, to assist and audit our year end December 31, 2025 reserve estimates in accordance with the rules and regulations of the SEC in Regulation S–X, Rule 4–10. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, technical and economic data including well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, pricing adjustments for differentials, and our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking.

The estimates used in determining valuation of oil and gas properties are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine assets fair values. As discussed above, estimated fair values assigned to proved and unproved properties are dependent on estimates of reserve quantities, future commodity prices, as well as development and operating costs. If reserve quantities or future commodity prices are lower than those used as inputs to determine estimates of acquisition–date fair values, the likelihood increases that certain costs may be determined to not be recoverable and ultimately be impaired.

We have several financial instruments which were evaluated for embedded derivatives and bifurcation in accordance with ASC 815 at the time of issuance. Pursuant to ASC 815, we have determined that the Series F Preferred Stock should be classified as mezzanine equity because it is currently redeemable at the Series F Preferred Stockholder’s option. Additionally, we determined that certain features of the Series F Preferred Stock require bifurcation and separate accounting as embedded derivatives. We engaged a third–party valuation expert to assist in preparing the fair value of the Series F Preferred Stock embedded derivatives as of December 31, 2025. These estimates were derived using a Monte Carlo simulation model as of December 31, 2025, assuming a transaction discount of 32.5%, a risk–free rate of 3.5%, and a preferred equity volatility rate of 54.0%. All of the significant inputs used in the Monte Carlo simulation as of December 31, 2025 are based on either terms in the Series F Preferred Stock Certificate of Designation or management assumptions, which are considered unobservable market data inputs.

Therefore, in accordance with ASC 815, as of December 31, 2025, we have recorded the embedded derivatives associated with the Series F Preferred Stock and the Series F Preferred Stock Warrants at fair value and will remeasure the fair value each reporting period with changes in fair value recognized as a component of loss on adjustment to fair value – embedded derivatives, debt, and warrants on our consolidated statements of operations.