PROP 10-K & 10-Q changes, risk factors and insider trading

Investing in our securities involves risks. Before you make a decision to buy our securities, in addition to the risks and uncertainties discussed above under “Cautionary Statement Regarding Forward-Looking Forward–Looking Statements,” you should carefully consider the specific risks set forth herein and the risks set forth in other filings we make with the SEC from time to time, together with other information in this Annual Report. If any of these risks actually occur, it may materially harm our business, financial condition, liquidity and results of operations. As a result, the market price of our securities could decline, and you could lose all or part of your investment. Additionally, Additionally, the risks and uncertainties described in this Annual Report are not the only risks and uncertainties that we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may become material and adversely affect our business.

While not an exhaustive list, the principal risks that we believe could adversely affect our business, financial conditioncondition, or results of operations include:

Other than the Genesis Bolt-on Assets, the Genesis Assets currently have no producing properties and thereThere is no assurance that we will be able to successfully drill producing wells. If theany Genesisof Assetsour assets are not commercially productive of crude oil or natural gas, any funds funds spent on exploration and production may be lost.

All of the Genesis Assets, other than the Genesis Bolt-on Assets, are in the pre-production stage and thereThere is no assurance that we will be able to obtain the requisite permits to begin drilling orcontinue successfully drilldrilling producing wells. TheSome Genesisof Assets,our other than the Genesis Bolt-on Assets,assets are not currently connected to the electrical grid or transportation, transportation, nor have we engaged service providers or contractors, necessary for the productive development of the assets and there is no assurance that we will be able to obtain the electrification, transportation or services necessary at economic costs, if at all. WeIf are dependent on establishing sufficient reserves at the Genesis Assets for additional cash flow and a returnany of our investment.assets If the Genesis Assets are not economic, all of the funds that we have invested,invested in such assets, or will invest,invest in such assets, will be lost. In addition, the failure of theour Genesisassets Assets to produce commercially may make it more difficult for us to raise additional funds in the form of additional sale of our equity securities or working interests in other property in which we may acquire an interest.

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

All of the reserves attributable to the Genesis Assets, other than the Genesis Bolt-on Assets, are undeveloped asAs of December 31, 2024. 2025, 43% of our reserves were undeveloped. Development of proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated PUDproved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our PUDsproved undeveloped reserves as unproved reserves.

Oil, natural gasgas, and NGLs prices are highly volatile. An extended decline in commodity prices may adversely affect our business, financial condition condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Following the acquisition and development of our existing and future E&P assets, our revenues, profitabilityprofitability, and cash flows will depend upon the prices for oil, natural gasgas, and NGLs. The prices we may receive for oil, natural gasgas, 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 indebtednessindebtedness, and to obtain additional capital on attractive terms. Changes in oil, natural gasgas, and NGLs prices have a significant impact on the amount of oil, natural gasgas, and NGLs that we can produce economically, the value of our reserves and on our cash flows. Historically, world-wideworld–wide oil, natural gasgas, 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, 2024,2025, the average West Texas Intermediate spot price was $76.63,$65.38, as compared to an average price of $77.58$76.63 for the year ended December 31, 2023.2024. The average Henry Hub natural gas spot price during the year ended December 31, 2024 2025 was $2.19,$3.52, as compared to an average of $2.53$2.19 for the year ended December 31, 2023.2024.

Prices for oil, natural gasgas, and NGLs may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

We have entered into hedging arrangements to hedge a significant portion of oil and natural gas production and are therefore exposed to fluctuations in the price of oil, natural gasgas, and NGLs andwhich willcould be affected by continuing and prolonged declines in such prices. Any future hedging activities we may engage in may result in financial losses or could reduce our income.

Oil, natural gas, and NGL prices are volatile,volatile; therefore, we hedge a significant portion of oil and natural gas production to reduce our exposure to adverse fluctuations in these prices. Our current derivative arrangements consist of crude oil and natural gas swaps but we could enter into additional derivative arrangements including swaps, collars and other instruments. Derivative arrangements could expose us to the risk of financial loss in some circumstances, including when: (i) production is less than the volume covered by the derivative instruments; (ii) the counterparty to the derivative instrument defaults on its contract obligations; or (iii) there is an increase in the differential between the underlying price in the derivative instrument and actual prices received. These types of derivative arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements. If oil, natural gas and NGL prices upon settlement of derivative swap contracts exceed the price at which commodities have been hedged, we will be obligated to make cash payments to counterparties, which could, in certain circumstances, be significant.

Drilling for and producing oil and natural gas wells is a high-riskhigh–risk activity with many uncertainties that could adversely affect our business, financial conditioncondition, or results of operations.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil, natural gasgas, 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-partythird–party operators may be curtailed, delayed or canceled. 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-partythird–party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-partythird–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.

Multi-well Multi–well pad drilling and project development may result in volatility in our operating results.

We intend to utilize multi-wellmulti–well pad drilling and project development where practical. Project development may involve more than one multi-well 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-wellmulti–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-wellmulti–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-D2–D and 3-D3–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-D2–D or 3-D3–D seismic data and other technologies requires greater pre-drillingpre–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-termlong–term production rates. In sum, the cost of drilling, completing, and operating any well is often uncertain, and new wells may not be productive.

The terms of our oil and natural gas leases often stipulate that the lease will terminate if not held by production, rentals, or otherwise some form of an extension payment to extend the term of the lease. If production in paying quantities is not established on units containing leases duringor an extension payment is not made prior to the nextexpiration year,date of the lease, then approximately 1,45114,300 net acres of our acreage will expire in 2025, 2026, approximately 11,6404,200 net acres will expire in 2026,2027, and approximately 4,941 8,200 net acres will expire in 20272028 and thereafter. Of the approximately 14,300 net acres which may expire in 2026, approximately 2,270 net acres, or 16%, will be held by production by the end of 2026, and approximately 3,500 net acres, or 25%, contain the extension terms, which we currently plan on exercising. While some expiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. Further, existing leases which are currently held by production may unexpectedly encounter operational, political, regulatory, or litigation challenges which could result in their termination. It is possible that market conditions at the time of negotiation could require us to agree to new leases on less favorablefavourable terms to us than the terms of the expired leases or cause us to lose the leases entirely. If our leases expire, we will lose our right to develop the related properties.

Our future results of operations are highly dependent on our ability to find, developdevelop, or acquire additional reserves.

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

Numerous uncertainties are inherent in estimating quantities of oil, natural gasgas, and NGLs reserves. The process of estimating oil, natural gas gas, and NGLs reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, including assumptions regarding future oil, natural gasgas, and NGLs prices, subsurface characterization, production levels and operating and development costs. Our reserve estimates as of December 31, 20242025 were prepared by CG&A. CG&A conducted a detailed review of our assets for the period covered by its reserve report using information provided by us.

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 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 gasgas, and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of non-recoverynon–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, nondiscriminatoryopen–access, non–discriminatory basis.

Our sales of oil and NGLs are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and NGLs by pipelines are regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and NGL pipelines to fulfillfulfil the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and NGL pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatorynon–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.

As an alternative to pipeline transportation, any transportation of our crude oil and NGLs by rail will also be subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and the Federal Railroad Administration (“FRA”) of the Department of Transportation under the Hazardous Materials Regulations at 49 CFR Parts 171-180,171–180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

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-establishedwell–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 favorablefavourable 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, productionproduction, 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 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-partiesthird–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 somethe recent periodspast 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-widefield–wide rules that could adversely affect development activities or production relating to those formations. Such an eventevents 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 increaseincreases 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 conditioncondition, or results of operations. All of the producing properties and reserves included in the Central Weld Assets are located in the DJ Basin. As a result, the transaction increases the risks we face with respect to the geographic concentration of our properties.

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-relatedweather–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 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 gasgas, and NGLs exploration, productionproduction, 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 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 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-partythird–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 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 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 isadopted currentlynew assessing draftcumulative impact rules pursuanton toOctober this15, law,2024. which,These if finalized as proposed, wouldrules 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, DIdisproportionately impacted communities, and “cumulatively impacted communities.” The draft rules would also set GHG emissions intensity targets for oil and natural gas operators and require regulators to consider such 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.

The threat of climate change continues to attract considerable attention in the U.S. and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-tradecap–and–trade programs, carbon taxes, GHG disclosure obligations and regulations that directly limit GHG emissions from certain sources. Former President Biden identified addressing climate change as a priority under his administration and issued executive orders related to that goal. For example, in January 2024, the Biden administration announced a temporary pause on the U.S. Department of Energy’s (“DOE”) review of pending applications for authorization to export LNG to countries that have not entered into free trade agreements (“FTAs”) with the U.S. (so-calledso–called non-FTAnon–FTA countries) until the DOE updates its underlying analyses for such authorizations using more current data to account for considerations like potential energy cost increases for consumers and manufacturers or the latest assessment of the impact of GHG emissions. WhileAlthough thisPresident pauseTrump’s mayadministration nothas 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 production, and development activities, it mayor affect the demand for our products, which could have a material adverse effect on our business and financial position.

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 new 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 sources for the first time ever, known as OOOOc. Under the final rules, states havehad two years to prepare and submit their plans to impose methane emission controls on existing sources.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 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-emissionzero–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, for the first time ever, imposes a fee on GHG emissions from certain facilities,and was signed into law in August 2022. The methane emissions charge would starthave in calendar year 2024started at $900 per ton of methane,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. Calculation of the fee is based on certain thresholds established in the IRA. 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. TheHowever, in early 2025 Congress used the Congressional Review Act to void the implementing rule. A future Congress could implement a similar methane charge and the 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-lower– or zero-carbonzero–carbon emissions alternatives. Furthermore, on March 6, 2024, the SEC finalized a rule requiring the reporting of climate-related climate–related risks and financial impacts, as well as GHG emissions for larger companies. Compliance dates under the final rule arewere to be phased in by registrant category.category Smallerwith reporting companies will be required to incorporate climate-related disclosures into their filings beginning in fiscal year 2027. Acceleratedsome filers willrequired be required to incorporate the disclosures in fiscal year 2026,2025 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 wellthe asSEC disclosureeither reconsiders the rules or resumes its defense of Scope 1 and 2 GHG emissions, if material, in fiscal year 2028, and limited assurance attestation reports related to the same by fiscal year 2031. Large accelerated filers will be required to incorporate the disclosures in fiscal year 2025, with Scope 1 and 2 GHG emissions disclosures, if material, in fiscal year 2026, and attestation reports by fiscal year 2029. While we are still assessing our obligations under the rule, complying with such obligations may result in increased costs.rules.

States have also implemented or are considering implementing laws and regulations that would require climate-relatedclimate–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-relatedclimate–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 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-changeclimate–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-sponsoredNations–sponsored Paris Agreement, though non-binding,non–binding, calls for signatory nations to limit their GHG emissions through individually-determinedindividually–determined reduction goals every five years after 2020. In February 2021, former President Biden recommitted the U.S. to long-term international goals to reduce emissions, including those under the Paris Agreement. Former President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50 to 52 percent from 2005 levels in economy-wide net GHG emissions by 2030. 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 fulfillfulfil 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,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.

Litigation risks are also increasing, as a number of states, municipalities, environmental organizations and other plaintiffs have sought to bring suits against oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such energy companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore, are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Involvement Involvement in such a case, regardless of the substance of the allegations, could have adverse reputational and financial impacts and an unfavorable unfavourable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition or operations.

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-fossilnon–fossil fuel energy related sectors. Certain institutional lenders who provide financing to fossil-fuelfossil–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 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 sub–alliances of GFANZ generally require participants to set short-term,short–term, sector-specificsector–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-relatedclimate–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 Financial System to identify key issues and potential solutions for the climate-relatedclimate–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-relatedclimate–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 favorablefavourable 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, 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-relatedfuel–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, change, investor and societal expectations regarding voluntary ESG-relatedESG–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 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-relatedESG–related targets in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-relatedESG–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.

Restrictions and regulations regarding hydraulic fracturing could result in increased costs, delays and cancellations in our planned oil, natural gas gas, and NGLs exploration, productionproduction, and development activities.

Our operations will include hydraulic fracturing activities.activities, Hydraulicwhich fracturing isare typically regulated by state oil and natural gas commissions, but the practice continues to attract considerable public, scientific and governmental attention in certain parts of the country, resulting in increased scrutiny and regulation, including by federal agencies. Many states have adopted rules that impose new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. For example, Colorado requires the disclosure of chemicals used in hydraulic fracturing and recently extended setback requirements for drilling activities. Local governments may also impose, or attempt to impose, restrictions on the time, place, and manner in which hydraulic fracturing activities may occur. Some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including temporary or permanent bans, additional permit requirements, operational restrictions, and chemical disclosure obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. The EPA has also asserted federal regulatory authority over certain aspects of hydraulic fracturing. For example, in December 2023, the EPA issued final rules that update new source performance standard requirements and that will impose more stringent controls on methane and volatile organic compounds emissions from oil and natural gas development and production operations, including hydraulic fracturing and other well completion activity. Additionally, certain federal and state agencies have evaluated or are evaluating potential impacts of hydraulic fracturing on drinking water sources or seismic events. These ongoing studies could spur initiatives to further regulate hydraulic fracturing or otherwise make it more difficult and costly to perform hydraulic fracturing activities. Any new or more stringent federal, state, local or other applicable legal requirements such as presidential executive orders or state or local ballot initiatives relating to hydraulic fracturing that impose restrictions, delays or cancellations in areas where we plan to operate could cause us to incur potentially significant added costs to comply with such requirements or experience delays, curtailment, or preclusion from the pursuit of exploration, development or production activities.

Our planned oil, natural gasgas, and NGLs exploration and production activities could be adversely impacted by restrictions on our ability to obtain water or dispose of produced water.

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 recently 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 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 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 recently 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 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.

Laws and regulations pertaining to the protection of threatened and endangered species and their habitats could delay, restrict or prohibit our planned oil, natural gas gas, and NGLs exploration and production operations and adversely affect the development and production of our reserves.

Our discussion includes forward–looking statements based upon current expectations that involve risks and uncertainties, such as our plans, objectives, expectations and intentions. Actual results and the timing of events could differ materially from those anticipated in these forward–looking statements as a result of a number of factors, including those described under the headings “Risk Factors” and “Cautionary Statement Regarding Forward-LookingForward–Looking Statements” appearing elsewhere in the Annual Report. Except as otherwise indicated or required by the context, references to the “Company,” “we,” “us,” “our” or similar terms refer to Prairie Operating Co.

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.U.S., as Weld County boasts some of the lowest break-evenbreak–even prices in the U.S., and has a long production history thatwhich 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 82%approximately 83% of Colorado’s oil production asto of December 2024.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 seekstrive to deliver energy in an environmentally efficient manner by deploying deploying next-generationnext–generation technology and techniques. In addition to growing production through our drilling operations, we also seekintend to growcontinue 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 January 11, 2024, we and one of our subsidiaries entered into the NRO Agreement to acquire the assets of NRO. On October 1, 2024, we closed the NRO Acquisition and paid $49.6 million to the sellersNRO in cash, using cash on hand, the proceeds from the issuance of Common Stock, and a portion of the proceeds from the issuance of a $15.0 million convertible promissory note (the “Senior Convertible Note.Note”) Weto completedYA theII finalPN, settlement with NRO in December 2024, which resulted inLTD., a finalCayman purchaseIslands price ofexempt $55.5limited company million.(“Yorkville”).

As previously discussed, weWe acquired our cryptocurrency mining operations in May 2023, concurrent with the Merger.2023. On January 23, 2024, we sold all of our Miningcryptocurrency Equipmentminers for consideration consisting of (i) $1.0 million in cash and (ii) $1.0 million in deferred cash payments,payments (the “Deferred Purchase Price”), to be paid out of (a) 20% of the monthly net revenues received by the buyer associated with or otherwise attributable to the Miningcryptocurrency Equipmentminers until the aggregate amount of such payments equals $250,000 and (b) thereafter, 50% of the monthly net revenues received by the buyer associated with or otherwise attributable to the Miningcryptocurrency Equipment miners until the aggregate amount of such payments equals the Deferred Purchase Price, plus accrued interest.interest As(collectively, ofthe December“Crypto 31,Sale”). 2024,In July 2025, we have received $0.3$0.4 million ofto satisfy the remaining Deferred Purchase Price.Price note receivable.

The following table presents the components of our revenue, production, and average realized sales price for the periodsyears indicated:

Oil revenueRevenue and production.Production. For the year ended December 31, 2024,2025, the majority of our oiltotal production wasvolumes 96.1and MBblsrevenues were attributable to properties acquired in the Bayswater Acquisition, which closed on March 26, 2025. As such, our production and revenues for the year ended December 31, 2025 includes the production and resulting in oil revenue offrom $6.6 millionthe andBayswater anAcquisition averagefrom realizedMarch price26, of2025 $68.60through perDecember barrel.31, 2025. All of our production oilvolumes revenueand revenues for the year ended December 31, 2024 waswere derived from the assets acquired in the NRO Acquisition, which closed on October 1, 2024. We did not have any oil revenue prior to the NRO Acquisition.

The following table presents the components of our operating expenses for the periodsyears indicated:

The following discussion and analysis of our financial condition and results of operations for the three and six months ended MarchJune 31,30, 2026 and 2025 should be read in conjunction with our condensed condensed consolidated financial statements and related notes to those financial statements that are included elsewhere in this report, as well as our audited consolidated financial statements and related notes and the related “Management’s Discussion and Analysis of Financial Condition and Results or Operations” in our most recent Annual Report on Form 10-K for the fiscal year ended December 31, 2025. Additionally, refer to “Cautionary Statement Regarding Forward-looking Statements” at the beginning of this Quarterly Report on Form 10-Q. Except as otherwise indicated or required by the context, references to the “Company,” “we,” “us,” “our” or similar terms refer to Prairie Operating Co.

As of MarchJune 31,30, 2026, our assets included approximately 68,70068,500 net leasehold acres in, on and under approximately 99,50097,600 gross acres. In addition to growing production through our drilling operations, we intend to continue growing itsour business through accretive acquisitions, 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.

In December 2025, we moved our drilling rig to our Blehm pad and then our /Schneider pad, bothwhich consists of which10 arewells in Weld CountyCounty. and consist of five wells each. Completion activities at the Blehm and Schneider pads were in the final stages as of March 31, 2026 and theThese wells came online early in April 2026.2026 with initial average two-stream gross production of 700 Boe/d.

We then moved the drilling rig to our Elder East and West pad, which consists of nine wells. Drilling at the Elder East and West pad was completed during the first quarter of 2026 and completionthe activitieswells arecame ongoing, online in May 2026 with firstinitial average two-stream gross production expected towards the end of May915 2026.Boe/d.

TheIn February, we began drilling rig is currently at our Opal Coalbank pad, which consists of eight wells. DrillingCompletion activities at the Opal Coalbank pad completed earlybegan in AprilMay 20262026, and completion activities are expected to continue throughout the secondwells quartercame of 2026, with first production expectedonline towards the beginningend of theJune third2026 quarterwith initial average two-stream gross production of 2026.450 Boe/d.

Series F Preferred Stock Letter Agreements and the Series F SecuritiesPreferred PurchaseStock AgreementAnniversary Warrants Amendments

On March 25, 2026, we and the Series F Preferred Stockholder entered into the First Series F Preferred Stock Warrant Amendment, which, among other things, extended the issuance date of Series F Preferred Stock Anniversary Warrants from March 2626, 2026 to April 7, 2026 (which was subsequently further extended to July 8, 2026).2026.

On April 6, 2026, we and the Series F Preferred Stockholder entered into the Second Series F Preferred Stock Warrant Amendment. Among other things, the Second Series F Preferred Stock Warrant Amendment amended and restated the First Series F Preferred Stock Warrant Amendment to extend the issuance date of the Series F Preferred Stock Anniversary Warrants from April 77, 2026 to April 9, 2026.

Additionally, pursuant to the Series F Preferred Stock Letter Agreement, we issued the First Series F FirstPreferred Stock Penny Warrants to the Series F Preferred Stockholder, and agreed that, if on July 8, 2026, which date was subsequently extended to August 7, 2026 and further extended to August 31, 2026, for any reason, the Series F Preferred Stock Anniversary Warrants have not been issued to the Series F Preferred Stockholder, we will issue the Series F Second Penny Warrants. Further, perpursuant the Series F Preferred Stock Letter Agreement, upon the Series F Preferred Stockholders receipt of the Series F Preferred Stock Repurchase Price Price and the issuance of the First Series F FirstPreferred Stock Penny Warrants, the Series F Preferred Stockholder waived our obligation to pay the previously announced $3.0 million extension fee.

As of MarchJune 31,30, 2026, we had the following outstanding crude oil, natural gas, and NGL derivative contracts in place, which settle monthly and are indexed to NYMEX West Texas Intermediate, NYMEX Henry Hub, and Mount Belvieu OPIS, respectively:

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 price adjustments. We closed the Edge Acquisition on July 3, 2025, which included 13 operated wells on approximately 11,300 net acresacres, and funded the transaction by borrowing under our Credit Facility.

For the three months ended MarchJune 31,30, 2026, total revenue increased $69.845% to $98.9 million andfrom total$68.1 productionmillion increased 1,791 MBoe compared toduring the three months ended MarchJune 31,30, 2025. TheThis majoritychange was primarily driven by a 40% increase in average realized price per Boe (excluding the effects of thederivatives) and a 4% increase was in production volumes, attributable to theincremental Bayswaterproduction Acquisition,volumes which closed on March 26, 2025. Additionally, approximately 30% of the increase was attributable tofrom new wells coming online as development activities were completed throughout the secondfirst half of 2025 and the first quarter of 2026.

Lease operating expenses. For the three months ended MarchJune 31,30, 2026, lease operating expensesexpense (“LOE”) increased $12.8to $13.6 million compared to $11.3 million for the three months ended June 30, 2025, primarily driven by new wells coming online as development activities were completed throughout the second half of 2025 and the first quarter of 2026. Additionally, our transaction services agreement with Bayswater ended at the end of May 2025 and we fully took over field operations at that time, resulting in incremental employee and benefit expenses recognized during the three months ended June 30, 2026 compared to the three months ended MarchJune 31,30, 2025. These Theincreases increasewere partially offset by decreased operating costs across all categories during the three months ended June 30, 2026 compared to the three months ended June 30, 2025, as we continue to streamline efficiencies and optimize operating costs at the properties acquired in LOE was largely driven by increased production as a result of ourthe Bayswater Acquisition, which closed on March 26, 2025.Acquisition. Additionally, LOE includes $0.7$0.6 million of workover expenses incurred during the three months ended MarchJune 31, 30, 2026 and $0.5 million of non-operated LOE recognized during the three months ended MarchJune 31,30, 2026. We did not incur any workover expenses or recognize any non-operated LOE during the three months ended MarchJune 31,30, 2025.

Transportation and processing expenses. For the three months ended MarchJune 31,30, 2026, transportation and processing expenses increasedremained $1.6relatively flat at $2.4 million compared to $2.2 million for the three months ended MarchJune 31, 2025, primarily driven by increased production as a result of our Bayswater Acquisition, which closed on March 26,30, 2025.

Ad valorem and production taxes. For the threesix months ended MarchJune 31,30, 2026, ad valoremtransportation and productionprocessing taxesexpenses increased $5.8to $4.9 million compared to $2.4 million for the threesix months ended MarchJune 31,30, 2025. The increase in transportation and 2025,processing primarilyexpenses was largely driven by increased production as a result of our Bayswater Acquisition, which closed on March 26, 2025.2025, and new wells coming online as development activities were completed throughout the second half of 2025 and the first two quarters of 2026.

Depreciation,Ad depletion,valorem and amortization.production taxes. For the three months ended MarchJune 31,30, 2026, depreciation,ad depletion,valorem and amortizationproduction expensestaxes increased $13.7to $8.0 million compared to $6.4 million for the three months ended June 30, 2025. The increase in ad valorem and production taxes is attributable to incremental production fees levied by the state of Colorado beginning in January 2026 and incremental ad valorem for equipment on pad sites incurred during the three months ended MarchJune 31,30, 2025, largely attributable to increased production as a result of our Bayswater Acquisition,2026, which closedwere onnot Marchincurred 26,during the three months ended June 30, 2025.

Abandonment and impairment of unproved properties. For the three months ended MarchJune 31,30, 2026, we recorded $0.4$0.2 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 three months ended MarchJune 31,30, 2025.

General and administrative expenses. For the three months ended MarchJune 31,30, 2026, general and administrative expenses increaseddecreased $11.3to $12.0 million compared to $16.4 million for the three months ended March 31,June 30, 2025. ThisThe increase27% wasdecrease largelyin general and administrative expenses is attributable to incrementaldecreased non-cashinvestor stock–basedrelations compensationcosts andof $3.0 million, employee and benefit expenses of $7.7$1.6 millionmillion, drivenand bytransition theservices increaseagreement fees inassociated headcount as a result ofwith the Bayswater Acquisition,Acquisition whichof closed$0.7 on Marchmillion, 26,partially 2025.offset Additionally,with wean incurredincrease $3.3of $0.9 million in non-cash stock-based compensation expense and $0.8 million in other non-recurring litigation and severance expensessettlement during the three months ended March 31, 2026.expenses.

Other income (expenses)

The following table presents the components of our other income (expenses) for the periods indicated:

Interest expense. For the threesix months ended MarchJune 31,30, 2026, interest expense increased $6.8$7.7 million compared to the threesame monthsperiod ended March 31,of 2025, primarily driven by interest on the Credit Facility incurred during the periods.period. Refer to Liquidity and Capital Resources - Significant Sources of Liquidity below for a further discussion of the Credit Facility.

LossGain (loss) on derivatives, net. For the three months ended MarchJune 31,30, 2026, lossgain on derivatives, net was $177.1$45.1 million compared to $0.9$28.2 million for the three months ended June March30, 31, 2025. The change in lossgain on derivatives, net was primarily due to a $162.8$54.6 million increase in unrealized lossgain on derivatives driven by unfavorablefavorable changes in the fair value of our open derivative contracts as of MarchJune 31,30, 2026 compared to April 1, 2026. Additionally,This increase was partially offset with an increase in our realized loss on derivatives increasedof by $13.4$37.6 million for the three months ended MarchJune 31,30, 2026 due to unfavorable changes in cash settlements during the period compared to the three months ended MarchJune 31,30, 2025. Refer to Factors Affecting the Comparability of Financial Results – Commodity Prices above for a further discussion of our derivative contracts.

LossGain (loss) on adjustment to fair value – embeddedfinancial derivatives,instrument debt, and warrants.liabilities. 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 gain (loss) on adjustment to fair value – embeddedfinancial derivatives,instrument debt, and warrantsliabilities on our condensed consolidated statements of operations for the period. For the three months ended MarchJune 31,30, 2026, the lossgain on adjustment to fair value – embeddedfinancial derivatives,instrument debt, and warrantsliabilities reflects lossesgains on fair value of $24.3$53.6 million for the Series F Preferred Stock WarrantsAnniversary andWarrants, $0.4$10.9 million for the Subordinated Note Warrants, which were partially offset by gains on fair value of less than $0.1 million for the Series F Preferred Stock embedded derivatives. For the three months ended March 31, 2025, the loss on adjustment to fair value – embedded derivatives, debt, and warrants reflects losses on fair value of $5.5 million for the Senior Convertible Note and $0.1$0.7 million for the Subordinated NoteNote, which were partially offset by gainsa $15.3 million loss on fair value of $2.4 million for the Subordinatedissuance Noteof Warrants,the $0.8Incremental Share Right liability and a $1.8 million loss on millionfair value for the SEPA, and $0.1 million for the Series F Preferred Stock embedded derivatives recognized during the period. Refer to Liquidity and Capital Resources - Significant Sources of Liquidity below for a further discussionconversions of the Series F Preferred Stock Warrants and embedded derivatives and the Subordinated Note Warrants.Stock.

Income Tax (Expense) Benefit

For the three and six months ended MarchJune 31,30, 2026, we recognized income tax expense of $19.8 million and an income tax benefit of $38.4$18.6 million, respectively, resulting in an effective income tax raterates of 15.4% and 29.9%, respectively. The difference between our effective income tax rates and the statutory blended rates for both the three and six months ended June 30, 2026 relate to excess tax benefits from stock-based compensation awards and tax deduction limitations on the compensation of 20.1%.covered individuals. We did not recognize any income tax benefit or expense for the three six months ended MarchJune 31,30, 2025.

Adjusted EBITDA is derived from net income (loss) attributable to Prairie Operating Co. and is adjusted for income tax benefit, depreciation, depletion, and amortization, abandonment and impairment of unproved properties, properties, non-cash stock-based compensation, interest expense, netnet, unrealized (gain) loss on derivatives, non-cash (gain) loss on adjustment to fair value – embeddedfinancial derivatives,instrument debt, and warrants,liabilities, litigation and severance settlement expense, and income tax expense,expense (benefit), all as applicable. We adjust net income (loss) attributable to Prairie Operating Co. 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.

The following table presents the reconciliation of Net income (loss) attributable to Prairie Operating Co. to Adjusted EBITDA for the periods indicated:

Our production and development activities will require us to make significant operating and capital expenditures. In the second half of 2025 and throughout the first quartertwo quarters of 2026, our primary sources of liquidity liquidity were borrowings on our Credit Facility, which has a borrowing base of $475.0 million and an aggregate elected commitment of $475.0 million.

Additionally, on June 20, 2025, we entered into the Equity Distribution Agreement in connection with our 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. As of MarchJune 31,30, 2026, we had not have issued any772,594 shares under the ATM Offering.Offering, which resulted in net proceeds of $1.8 million.

We define working capital as current assets less current liabilities. As of MarchJune 30, 2026 and December 31, 2026,2025, we had a working capital deficit of $181.0$125.5 million and cash and cash equivalents of $0.3 million and as of December 31, 2025, we had a working capital deficit of $46.1 millionmillion, respectively, and cash and cash equivalents of less than $0.1 millionmillion.

Operating activities. Net cash provided by operating activities totaled $42.3$94.3 million and $16.9$9.7 million during the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. The $25.3$84.5 million increase in our net cash provided by operating activities was primarily attributable to increased revenue during the period, partially offset by increased operating expenses, largely driven by the Bayswater Acquisition, which closed on on March 26, 2025.

Investing activities. Net cash used in investing activities totaled $36.3$143.9 million and $528.4$522.3 million during the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. The $492.2$378.4 million decrease in our net cash used in investing activities was largely driven by cash paid for the Bayswater Acquisition of $474.6$467.5 million.million Additionally,during ourthe six months ended June 30, 2025, which was partially offset by a $78.6 million increase in expenditure for the development of oil and natural gas properties decreased $4.9 million during the threesix months ended MarchJune 31,30, 2026 compared to the three months ended March 31, 2025, primarily due to timing of capital projects.2026.

Financing activities. Net cash used in financing activities totaled $5.7 million for the three months ended March 31, 2026, and net cash provided by financing activities totaled $521.3$49.6 million and $518.0 million for the threesix months ended MarchJune 31,30, 2025.2026 and 2025, respectively. The $527.0 $468.4 million decrease in net cash usedprovided inby financing activities was mostly due to financing activities completed during the three months ended March 31, 2025 to fund the Bayswater Acquisition, which closed on March 26, 2025. These financing activities included $43.8 million from the issuance of Common Stock, net of related issuance costs of $3.1$3.3 million, $148.3 million from the issuance of the Series F Preferred Stock, net of related issuance costs of $1.2$11.1 million, and $349.0 $359.0 million from borrowings under the Credit Facility, net of related issuance costs of $12.5$15.7 million. Financing activities for the threesix months ended MarchJune 31,30, 2026 were attributable to the$134.0 $60.5 million of repaymentsborrowings on the Credit Facility, partially offset withby borrowingsrepayments of $56.0$64.0 million and Credit Facility amendment fees of $1.9 million. Additionally, we redeemed a portion of the Series F Preferred Stock for $19.0 million and issued shares of Common Stock under our ATM Offering, which resulted in net proceeds of $1.8 million.

Credit Facility. On December 16, 2024, we, as borrower, entered into a reserve–based credit agreement with Citi, as administrative agent and the financial institution party. On February 3, 2025, we entered into the first amendment to our reserve–based credit agreement with Citi, which among other things, increased the borrowing base and the aggregate elected commitments to $60.0 million. On March 26, 2025, we entered into into the Credit Facility,Facility Agreement, which amended and restated our existing reserve–based credit agreement with Citi. On June 6, 2025, we entered into the first amendment to our Credit Facility,Facility Agreement, which added Bank of America N.A. and West Texas National Bank as lenders under the Credit Facility. TheOn CreditJune Facility10, is2026, scheduledwe entered into the second amendment to mature on March 26, 2029 and provides for a maximum credit commitment of $1.0 billion. As of March 31, 2026, the Credit Facility hadAgreement, awhich among other things, reaffirmed the borrowing base of $475.0 millionmillion, modified certain covenants relating to our distributable free cash flow and an aggregatecertain electedother commitmentreporting and notice requirements, and increased the cadence of $475.0 million and includes a $47.5 million sublimit for the issuance of letters of credit. Thescheduled borrowing base is subject to semi–annual redeterminations based uponand the valuenumber of our oil and gas properties as determined in a reserve report immediately preceding April 1st and October 1st of each year, subject to certain interim redeterminations. The borrowing base ofredeterminations $475.0which may millionoccur wasin reaffirmedany withfiscal the 2025 mid–year redetermination.year.