Prairie Operating Co. 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31 , 2025 ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ___________ to __________ Commission File Number 001-41895 Prairie Operating Co. (Exact name of registrant as specified in its charter) Delaware 98-0357690 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 55 Waugh Drive , Suite 400 Houston , TX 77007 77007 (Address of principal executive offices) (Zip Code) ( 713 ) 716–1200 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Exchange Act: Title of each Class Trading Symbol(s) Name of each Exchange on which registered Common stock, $0.01 par value PROP The Nasdaq Stock Market LLC Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if a registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes ☐ No ☒ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S–T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non–accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b–2 of the Exchange Act. Large accelerated filer ☐ Accelerated filer ☐ Non–accelerated filer ☒ Smaller reporting company ☒ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes–Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive–based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D–1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Act). ☐ The aggregate market value of the voting and non–voting common equity held by non–affiliates of the registrant, based on the closing price of the shares of common stock on the Nasdaq Capital Market on June 30, 2025, was $ 74,131,123 . The registrant had 76,574,223 shares of common stock outstanding as of March 25, 2026. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Stockholders, scheduled to be held on June 3, 2026, are incorporated by reference into Part III of this Annual Report on Form 10–K. TABLE OF CONTENTS PART I Item 1. Business 3 Item 1A. Risk Factors 20 Item 1B. Unresolved Staff Comments 40 Item 1C. Cybersecurity 40 Item 2. Properties 41 Item 3. Legal Proceedings 41 Item 4. Mine Safety Disclosures 41 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 42 Item 6 [Reserved] 42 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 43 Item 8. Financial Statements and Supplementary Data 55 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 98 Item 9A. Controls and Procedures 98 Item 9B. Other Information 98 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 98 PART III Item 10. Directors, Executive Officers and Corporate Governance 99 Item 11. Executive Compensation 99 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 99 Item 13. Certain Relationships and Related Transactions, and Director Independence 99 Item 14. Principal Accounting Fees and Services 99 PART IV Item 15. Exhibits and Financial Statement Schedules 100 Item 16. Form 10–K Summary 100 Signatures 101 i Table of Contents Definitions of Certain Terms and Conventions Used Herein “Bbl or barrel” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons. “ Boe ” means barrel of oil equivalent, using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate. “ Boe/d ” means Boe per day. “ developed acres ” or “ developed acreage ” means the number of acres that are allocated or assignable to producing wells or wells capable of production. “ developed reserves ” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. “ development well ” means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. “ exploratory well ” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. “ gross acres ” or “ gross wells ” means the total acres or wells in which the Company owns a working interest. “ Mbbl ” means one thousand Bbls. “ Mboe ” means one thousand Boe. “ Mcf ” means one thousand cubic feet. “ MMboe ” means one million Boe. “ MMBtu ” means one million British Thermal Units. “ MMcf ” means one million cubic feet. “ net acres ” or “ net wells ” means the sum of the fractional working interests the Company owns in gross acres or gross wells. “NGLs” means natural gas liquids. “ productive wells ” means a well productive of oil or natural gas. ii Table of Contents “ proved reserves ” means those quantities of oil, natural gas, and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or we must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S–X, Rule 4–10(a)(22). “ proved undeveloped reserves ” means proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time. “ reserves ” means estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means– of delivering crude oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non–productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). “ Standardized Measure ” means the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. “ undeveloped acres ” or “ undeveloped acreage ” means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. “ unproved properties ” means properties with no proved reserves. iii Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD – LOOKING STATEMENTS This Annual Report on Form 10–K (this “Annual Report”) contains statements that are forward–looking and as such are not historical facts. These forward–looking statements include, without limitation, statements regarding future financial performance, business strategies, expansion plans, future results of operations, estimated revenues, losses, projected costs, prospects, plans and objectives of management. These forward–looking statements are based on our management’s current expectations, estimates, projections and beliefs, as well as a number of assumptions concerning future events, and are not guarantees of performance. Such statements can be identified by the fact that they do not relate strictly to historical or current facts. When used in this Annual Report, words such as “may,” “should,” “could,” “would,” “expect,” “plan,” “anticipate,” “intend,” “believe,” “estimate,” “continue,” “project” or the negative of such terms or other similar expressions may identify forward–looking statements, but the absence of these words does not mean that a statement is not forward–looking. Forward–looking statements in this Annual Report include, but are not limited to, statements about: ● estimates of our oil, natural gas, and NGL reserves; ● drilling prospects, inventories, projects, and programs; ● estimates of our future oil and natural gas production, including estimates of any increases or decreases in our production; ● financial strategy, liquidity and capital required for our development program and other capital expenditures; ● the availability and adequacy of cash flow to meet our requirements; ● the availability of additional capital for our operations; ● changes in our business and growth strategy, including our ability to successfully operate and expand our business; ● our integration of acquisitions, ● changes or developments in applicable laws or regulations, including with respect to taxes; and ● actions taken or not taken by third–parties, including our contractors and competitors. The forward–looking statements contained in this Annual Report are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward–looking statements involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward–looking statements. These risks include, but are not limited to: ● our ability to fund our development and drilling plan; ● our ability to grow our operations, and to fund such operations, on the anticipated timeline or at all; ● uncertainties inherent in estimating quantities of oil, natural gas, and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; ● commodity price and cost volatility and inflation; ● our ability to obtain and maintain necessary permits and approvals to develop our assets; 1 Table of Contents ● safety and environmental requirements that may subject us to unanticipated liabilities; ● changes in the regulations governing our business and operations, including the businesses, assets and operations we have acquired or may acquire in the future, such as, but not limited to, those pertaining to the environment, our drilling program and the pricing of our future production; ● our success in retaining or recruiting, or changes required in, our officers, key employees or directors; ● general economic, financial, legal, political, and business conditions and changes in domestic and foreign markets; ● the risks related to the growth of our business, including our ability to successfully integrate, and recognize the anticipated benefits of, our recent acquisitions and any future acquisitions; ● the effects of competition on our future business; ● changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs and other trade barriers, and any resulting trade tensions; and ● other factors detailed under the section entitled “Risk Factors” and in our periodic filings with the Securities and Exchange Commission (“SEC”). These risks are not exhaustive. Other sections of this Annual Report include additional factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time, and it is not possible for our management to predict all risk factors nor can we assess the effects of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in, or implied by, any forward–looking statements. Additionally, our discussions of certain environmental, social and governance (“ESG”) matters and issues herein are informed by various standards and frameworks (including standards for the measurement of underlying data), and the interests of various stakeholders. As such, the discussions may not necessarily be “material” under the federal securities laws for SEC reporting purposes. Furthermore, much of this information is subject to methodological considerations or information, including from third parties, that is still evolving and subject to change. For example, our disclosures based on any standards may change due to revisions in framework requirements, availability of information, changes in our business or applicable government policies, or other factors, some of which may be beyond our control. Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas, and NGLs that are ultimately recovered. Our SEC filings are available publicly on the SEC website at www.sec.gov . Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward–looking statements. Accordingly, forward–looking statements in this Annual Report should not be relied upon as representing our views as of any subsequent date, and we undertake no obligation to update or revise any forward–looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward–looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. 2 Table of Contents PART I Item 1. Business Overview Prairie Operating Co. (the “Company,” “we,” “our” or “us”) is an independent oil and natural 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 Denver–Julesburg Basin in Colorado (the “DJ Basin”). We believe the DJ Basin to be one of the premier resource plays in the United States (“U.S.”), as Weld County boasts some of the lowest break–even prices in the U.S., and has a long production history that 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 83% of Colorado’s oil production as of December 2025. We seek 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 also seek to grow our 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. As of December 31, 2025, our assets consist of our Central Weld Assets (as defined herein), made up of approximately 45,000 net leasehold acres, on and under approximately 56,200 gross acres, and our Genesis Assets (as defined herein), made up of approximately 23,000 net leasehold acres in, on and under approximately 42,000 gross acres. The majority of our Central Weld Assets were acquired from Nickel Road Development LLC and Nickel Road Operating LLC (collectively, “NRO”) in October 2024, from Bayswater Resources, LLC, Bayswater Fund III–A, LLC, Bayswater Fund III–B, LLC, Bayswater Fund IV–A, LP, Bayswater Fund IV–B, LP, Bayswater Fund IV–Annex, LP, and Bayswater Exploration & Production, LLC (collectively, “Bayswater”) in March 2025, and from Edge Energy II LLC (“Edge Energy”) in July 2025 and the majority of our Genesis Assets were acquired in 2023. Business Strategy We intend to increase stakeholder value by using the following strategies to grow our reserves, production, and cash flow in a capital efficient and environmentally conscious manner: Deliver growth through the development of extensive drilling inventory and acreage. We plan to target rich, immediately accessible permitted locations and organically grow development through infill leasing. We believe this will allow us to increase production, reserves and cash flow which generate favourable returns. Fund drilling program with free cash flow and retain low leverage. We aim to maintain a conservative financial position and develop primarily through available cash flow from operations. We plan to allocate capital in a disciplined manner and proactively manage our cost structure. Maximize returns and capital efficiency. We plan to utilize the latest technology in 3–D seismic mapping and geo–steering to decrease drill times and improve well results. Additionally, our management’s extensive experience allows us to deploy the latest drilling and completion methodologies and apply the industry best practices to increase overall estimated ultimate recovery versus prior generation wells. Acquisition strategy focused on core area in the DJ Basin . We plan to pursue accretive acquisitions through an opportunistic roll–up strategy by continually evaluating acquisition opportunities to expand our position. Our management team has a long track record of successfully sourcing and integrating acquisitions. Proactively manage regulatory, environmental, safety, and community matters. Our development approach prioritizes the well–being of environment, communities, and wildlife, and we actively engage with regulatory agencies to minimize surface impact while maximizing efficiency of our development program. Additionally, our operations emphasize utilizing technology and innovation to minimize impacts. 3 Table of Contents Our Properties and Operations Central Weld Assets On January 11, 2024, we and one of our subsidiaries entered into an asset purchase agreement (the “NRO Agreement”) with NRO to acquire the assets of NRO (the “NRO Acquisition”). On October 1, 2024, we closed the NRO Acquisition and paid $49.6 million to NRO in cash. On February 6, 2025, we and certain of our subsidiaries entered into a purchase and sale agreement with Bayswater, pursuant to which we agreed to acquire certain oil and natural gas assets (the “Bayswater Assets”) for a purchase price of $602.8 million, subject to certain closing price adjustments (the “Bayswater Acquisition”). 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 acquisition of additional working interest (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, par value $0.01 per share (“Common Stock”) to Bayswater (the “Equity Consideration”). We completed the final settlement with Bayswater on October 15, 2025, resulting in a final consideration of $475.6 million. 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. Additionally, we plan to drill and complete approximately 40 gross wells in 2026 with further development planned in 2027. Our drilling plan is based on current commodity prices, and an increase or decrease in commodity prices could impact the number of wells we actually drill. There is no guarantee that our development plan will result in the successful production of economic quantities of oil and natural gas. Our development plan is based on assumptions from management’s prior experience and such experience may not be indicative of the success of our development plans. 4 Table of Contents The following table summarizes the permitting status of our Central Weld Assets gross undeveloped locations as of December 31, 2025: Gross Undeveloped Locations Weld Oil & Gas Location Assessment Approved 128 Colorado Energy & Carbon Management Commission Approved 128 Colorado Energy & Carbon Management Commission Fully Permitted 103 For more information regarding regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations. Genesis Assets In May 2023, we consummated the purchase of oil and natural gas leases from Exok, Inc. (“Exok”), including all of Exok’s right, title, and interest in, to and under approximately 3,200 net leasehold acres located in Weld County, Colorado, together with certain other associated assets, data, and records, for $3.0 million (the “Exok Transaction”). On August 15, 2023, we exercised the option we acquired in the Exok Transaction to purchase additional oil and natural gas leases from Exok, consisting of approximately 20,300 net leasehold acres in, on and under approximately 32,580 gross acres (the “Exok Option Purchase”) for total consideration of $25.3 million (collectively, the “Initial Genesis Assets”). On February 5, 2024, we acquired 1,280 gross leasehold acres on drillable spacing unit and eight proved undeveloped drilling located in the DJ Basin, made up of 835 net leasehold acres, from a private seller for $0.9 million. In August 2025, we completed our third acquisition from Exok, acquiring approximately 5,000 net acres for $1.6 million (the “Third Exok Acquisition”). We refer to these assets collectively as the “Genesis Assets.” As of December 31, 2025, the total Genesis Assets include approximately 23,000 net leasehold acres in, on and under approximately 42,000 gross acres. As of December 31, 2025, approximately 7,900 net acres of the Genesis Assets have expired. The expired leases were deemed non–core; therefore, we elected to not re–new the leases at their expiration date. Approximately 92% of the net leasehold of our Genesis Assets are leased from private landowners, with the remaining 8% under State of Colorado or Federal leases. 91% of the net Genesis Assets acreage is held by crude oil and natural gas leases with varying expiration dates, some with options to extend ranging from one to four years. The leases can be held indefinitely by production. 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 Genesis Assets in the third quarter of 2024 by drilling eight wells in the Shelduck South development, all of which began producing in February 2025. Our 2026 drilling plan includes drilling an additional four gross wells on our Gensis Assets. Our drilling plan is based on current commodity prices, and an increase or decrease in commodity prices could impact the number of wells we actually drill. There is no guarantee that our development plan will result in the successful production of economic quantities of oil and natural gas. Our development plan is based on assumptions from management’s prior experience and such experience may not be indicative of the success of our development plans. The following table summarizes the permitting status of our identified well locations with respect to our Genesis Assets as of December 31, 2025: Expected Three Mile Lateral Count Expected Two Mile Lateral Count Weld Oil & Gas Location Assessment Approved 18 54 Colorado Energy & Carbon Management Commission Approved 18 54 Colorado Energy & Carbon Management Commission Fully Permitted 10 10 For more information regarding regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations below. 5 Table of Contents Reserves 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: Year Ended December 31, 2025 2024 Net reserve volumes: Proved developed producing: Oil (MBbls) 27,900 1,967 Natural gas (MMcf) 122,975 4,887 NGL (MBbls) 17,974 600 Total (MBoe) (1) 66,370 3,382 Proved developed non–producing: Oil (MBbls) 1,406 1,782 Natural gas (MMcf) 2,258 4,419 NGL (MBbls) 330 536 Total (MBoe) (1) 2,112 3,054 Proved undeveloped: Oil (MBbls) 30,725 10,594 Natural gas (MMcf) 70,041 31,932 NGL (MBbls) 10,238 3,767 Total (MBoe) (1) 52,637 19,683 Total proved: Oil (MBbls) 60,031 14,343 Natural gas (MMcf) 195,274 41,238 NGL (MBbls) 28,542 4,903 Total (MBoe) (1) 121,119 26,119 Reserves data (in thousands): Standardized measure of discounted future net cash flows $ 851,702 $ 255,142 PV–10 (2) $ 1,219,814 $ 303,159 SEC Prices (3) : Oil (per Bbl) $ 65.34 $ 74.63 Natural gas (per MMBtu) $ 3.39 $ 1.60 NGL (per Bbl) $ 19.28 $ 21.63 (1) Assumes a ratio of 6 MMcf of natural gas per MBoe. (2) PV–10 is a financial measure not presented in accordance with U.S. GAAP. PV–10 is derived from the 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%. (3) Our estimated proved reserves and the related net revenues were determined using the 12–month unweighted arithmetic average of the first–day–of–the–month price for each month in the period January through December (“SEC Prices”). The SEC Prices are adjusted for treating costs and/or crude quality and gravity corrections. 6 Table of Contents Reconciliation of Standardized Measure to PV–10 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: Year Ended December 31, 2025 2024 (In thousands) Standardized Measure $ 851,702 $ 255,142 Present value of future income taxes discounted at 10% 368,112 48,017 PV–10 $ 1,219,814 $ 303,159 Proved Reserves The following table presents the changes in our estimated proved reserves during the year ended December 31, 2025: Total (MBoe) Proved reserves as of January 1, 2025 26,119 Acquisitions of reserves 95,344 Production (6,748 ) Revisions to previous estimates 6,404 Proved reserves as of December 31, 2025 121,119 As of December 31, 2025, our estimated proved reserves are 121.1 MMBoe, which are primarily comprised of 95.3 MMBoe reserves acquired during the year ended December 31, 2025 and revisions to previous reserve estimates of 6.4 MMBoe. Proved Undeveloped Reserves Proved undeveloped oil and natural gas reserves are reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas which are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances. The following table presents the changes in our estimated proved undeveloped reserves during the year ended December 31, 2025: Total (MBoe) Proved undeveloped reserves as of January 1, 2025 19,683 Converted to proved developed reserves (10,452 ) Acquisitions of reserves 41,452 Revisions to previous estimates 1,954 Proved undeveloped reserves as of December 31, 2025 52,637 During the year ended December 31, 2025, we converted 20% of our proved undeveloped reserves, which is comprised of 34 gross wells representing net reserves of 10.5 MMBoe, at an average cost of $3.9 million net per well. Additionally, we had acquisitions of proved undeveloped reserves of 41.5 MMBoe and revisions of 2.0 MMBoe during the year ended December 31, 2025. 7 Table of Contents 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. Qualifications of Technical Persons Our proved reserve estimates as of December 31, 2025 and 2024 included in this Annual Report have been prepared by CG&A, an independent Petroleum Reserve Evaluation Firm. Our full reserve report as of December 31, 2025, prepared by CG&A, should be read in its entirety, and is attached as Exhibit 99.1 to this Annual Report. These proved reserve estimates were prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers (“SPE”) and the guidelines established by the SEC. The technical personnel responsible for preparing the reserve estimates of CG&A meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the SPE. The estimates of our reserves presented in the CG&A reserve report were overseen by W. Todd Brooker. Mr. Brooker is the President of CG&A and has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, expert reporting and testimony, field/reservoir studies, pipeline resource assessments, field development planning and acquisition/divestiture analysis. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honours from The University of Texas at Austin in 1989 with a Bachelor of Science Degree in Petroleum Engineering. He is a registered Professional Engineer in the State of Texas (License #83462), and a member of the SPE and the Society of Petroleum Evaluation Engineers (“SPEE”). No director, officer or key employee of CG&A has any financial ownership in use or any of our affiliates. CG&A’s compensation for preparation of its report is not contingent upon the results obtained and reported. CG&A has not performed other work for us or any of our affiliates that would affect its objectivity. CG&A does not own an interest in our properties. Timothy Smith, our Senior Vice President of Engineering, works closely with CG&A to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their preparation of reserve estimates. Mr. Smith is primarily responsible for overseeing the preparation of both our internal and external reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserves Information promulgated by the SPE. Mr. Smith’s qualifications include a Bachelor of Arts Degree in Geology from the University of Colorado at Boulder, a Master of Science Degree in Civil Engineering from Colorado State University, and a Master of Science Degree in Petroleum Engineering from the University of Southern California. Additionally, he has 16 years of practical experience in estimating and evaluating reserve information, the majority of which have included overseeing, estimating, and evaluating reserves and is a member of SPE. Internal Controls over Estimated Proved Reserves The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. As part of this process, we provide historical information to the independent reserve engineers relating to the ownership interest, oil and natural gas production, well data, commodity prices, and operating and development costs of our properties. Technical, geological, and engineering reviews of our assets are performed throughout the year and data obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. These procedures are intended to ensure reliability of reserve estimations, and include the review and verification of historical production data, working interests, net revenue interest, lease operating statements, capital costs, severance and ad valorem taxes and the review of all significant reserve changes and all new proved undeveloped reserves additions. 8 Table of Contents Production, Average Sales Prices, and Production Costs Our production volumes, average sales prices, and average production costs are as follows: Year Ended December 31, 2025 (1) 2024 Production: Oil (MBbls) 3,406 96 Natural gas (MMcf) 10,753 245 NGL (MBbls) 1,550 33 Total production (MBoe) (2) 6,748 170 Average sales volumes per day (Boe/d) 18,487 464 Average sales price (excluding effects of derivatives): Oil (per MBbls) $ 59.91 $ 68.60 Natural gas (per MMcf) $ 0.88 $ 2.25 NGL (per MBbls) $ 18.16 $ 24.03 Average price (per MBoe) (2) $ 35.81 $ 46.70 Average lease operating expenses (per Boe) $ 6.14 $ 7.44 (1) Total revenues and production for the year ended December 31, 2025, include revenue and production volumes from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. (2) MBoe is calculated using six MMcf of natural gas equivalent to one MBbl of oil. For additional information, refer to Part II – Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . 9 Table of Contents Productive Wells Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and crude oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have an interest and net wells are the sum of our fractional working interests owned in gross wells. The following table presents a summary of our productive wells as of December 31, 2025: Oil Operated Non–operated Total Gross Net Gross Net Gross Net Gross Net Productive wells 550 365 388 351 162 14 550 365 Drilling and Completion Activities The following tables present a summary of our operated development activity for the years indicated. Development wells consist of wells completed and/or turned to sales during the period, regardless of when drilling was initiated. Year Ended December 31, 2025 2024 Gross Net Gross Net Development wells turned to sales 33 30 8 6 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. As of December 31, 2025 Gross Net Development in–progress wells 10 7 We did not have any exploratory drilling activities or any dry holes during the years ended December 31, 2025 and 2024. Acreage The following table presents certain information regarding the total developed and undeveloped acreage in which we own a working interest as of December 31, 2025. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary. Developed Acres Undeveloped Acres Total Acres Gross Net Gross Net Gross Net DJ Basin 53,350 41,302 44,778 26,711 98,128 68,013 Certain leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table presents our undeveloped acreage, as of December 31, 2025, which will expire in the years indicated unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates. Expiring 2026 Expiring 2027 Expiring 2028 Expiring 2029 and Beyond Gross Net Gross Net Gross Net Gross Net DJ Basin 23,424 14,311 8,647 4,206 10,596 7,694 2,111 500 Approximately 14,311 net acres, or 21%, may expire in 2026 if production is not established or if we do not extend lease terms, of which approximately 2,269 net acres, or 16%, will be held by production by the end of 2026, and approximately 3,544 net acres, or 25%, contain the extension terms, which we plan on exercising. We intend to extend our strategic leases to the extent possible. Decisions to let certain leaseholds expire generally relate to areas outside of our core area of development or when the expirations do not pose material impacts to development plans or reserves. 10 Table of Contents Title to Properties 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. Commodity Price Risks and Price Risk Management Activities 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 . Customers 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. Transportation Commitments As a result of the Bayswater Acquisition, we are party to an oil transportation agreement which includes a minimum volume commitment, requiring us to transport a fixed determinable quantity of crude oil on a monthly basis. Under the terms of this agreement, we may be required to make periodic deficiency payments for any shortfalls in delivering the minimum gross volume to be transported by the counterparty. Additionally, one of our gas gathering contracts requires a monthly guaranteed payment intended to reimburse the counterparty for costs incurred to connect to the gathering facility. Refer to Part II – Item 8. Financial Statements and Supplementary Data – Note 12 – Commitments and Contingencies for additional discussion. Competition 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. 11 Table of Contents Regulation of the Oil and Natural Gas Industry Our operations are affected by extensive federal, state, and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes, and numerous other laws and regulations, including laws and regulations relating to environmental, health and safety matters. The jurisdictions in which we own and operate properties or assets for oil and natural gas production have statutory provisions regulating the exploration for and development and production of oil and natural gas, including, among other things, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the production and operation of wells and other facilities, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the proper abandonment of wells and pipelines. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the size of associated facilities, and the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Failure to comply with applicable laws and regulations can result in substantial penalties and the suspension or cessation of operations. Our competitors in the oil and natural gas industry are generally subject to similar regulatory requirements and restrictions to those which affect our operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently revised and amended through various legislative actions and rulemakings. Therefore, we are unable to predict the future costs or impact of compliance. Additional rulemakings, proposals and proceedings that affect the oil and natural gas industry are regularly considered at the federal, state, and various local government levels, including statutorily and through powers granted to various agencies that regulate our industry, and various court actions. We cannot predict when or whether any such future rulemakings, proposals or proceedings may become effective or if the outcomes will negatively affect our operations. 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. Regulation of Production of Oil, Natural Gas, and NGLs The production of oil, natural gas, and NGLs is subject to regulation under a wide range of local, state, and federal statutes, rules, orders, and regulations. Federal, state, and local statutes and regulations require, among other things, permits for drilling operations, drilling bonds, and reports concerning operations. Colorado, the state in which we own all of our properties, regulates drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Colorado also govern a number of conservation matters, including provisions for the spacing and unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing and well density, and procedures for proper plugging and abandonment of wells and associated facilities. These regulations effectively identify well densities by geologic formation and the appropriate spacing and pooling unit size to effectively drain the resources. These regulations can have the effect of limiting the amount of oil, natural gas, and NGLs that we can produce from our wells and limiting the number of wells or the locations where we can drill, although we can apply for exceptions to such regulations, including applications to increase well densities and reduce lease boundary setbacks to more effectively recover oil and natural gas resources. Moreover, Colorado imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction. Colorado also regulates drilling and operating activities by requiring, among other things, permits for new pad locations, the drilling of wells, best management practices and/or conditions of approval for operating wells, maintaining bonding requirements in order to drill or operate wells, regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Colorado laws also govern a number of environmental, health and safety matters that may impact our drilling and operating activities, including setbacks from buildings, schools, and other occupied areas, sensitive habitats and/or disproportionately impacted communities, consideration of alternative locations for new wells, the handling and disposal of waste materials, haul routes, prevention of venting and flaring, mitigation of noise, lighting, visual, odor, and dust impacts, air pollutant emissions permitting, protection of certain wildlife habitat, protection of public health, safety, welfare, and environment, and evaluation of cumulative impacts. 12 Table of Contents Regulation of Transportation and Sales of Oil Sales of oil, condensate, and NGLs from producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future. Our sales of crude oil are affected by the availability, terms, conditions and cost of transportation services. Transportation of oil in interstate commerce by common carrier pipelines is also subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non–discriminatory and that such rates and terms and conditions of service be filed with FERC. 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 and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from how it affects operations of our competitors who are similarly situated. The Federal Trade Commission (“FTC”) has the authority under the Federal Trade Commission Act (“FTCA”) and the Energy Independence and Security Act of 2007 (“EISA”) to regulate wholesale petroleum markets. The FTC has adopted anti–market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of approximately $1,510,803 as of 2025 (adjusted annually for inflation) per violation per day. Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. Regulation of Transportation and Sales of Natural Gas Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”), and by regulations and orders promulgated by FERC under the NGA. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations. FERC issued a series of orders in 1996 and 1997 to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been greatly reduced and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. 13 Table of Contents 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. We are required to observe such anti–market manipulation laws and related regulations enforced by FERC under the EPAct of 2005 and those enforced by the Commodity Futures Trading Commission (“CFTC”) under the Commodity Exchange Act, as amended (“CEA”), and CFTC regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce, as well as the market for financial instruments on such commodity, such as futures, options, or swaps. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1,487,712 as of 2025 (adjusted annually for inflation) or triple the monetary gain to the violator for violations of the anti–market manipulation sections of the CEA. Should we violate the anti–market manipulation laws and regulations, we could also be subject to related third–party damage claims by, among others, sellers, royalty owners and taxing authorities. 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. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC–regulated transportation services and federally unregulated gathering services relies on a fact–intensive analysis that is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. 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. Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in the state in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from how it affects operations of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Changes in law and to FERC and/or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines and intrastate pipelines. Changes in law and to FERC and state utility commission policies and regulations also may result in increased regulation of our business and operations, and we cannot predict what future action FERC or any state utility commission will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers, and marketers with which we compete. 14 Table of Contents Regulation of Environmental and Occupational Safety and Health Matters Our operations are subject to stringent federal, state and local laws and regulations governing the occupational safety and health aspects of our operations, the discharge of materials into the environment, and protection of the environment and natural resources (including threatened and endangered species and their habitats). Numerous governmental entities, including the U.S. Occupational Safety and Health Administration (“OSHA”), and U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, such as the Colorado Department of Public Health and Environment (the “CDPHE”), have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring costly investigation or actions. These laws and regulations may, among other things, (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment or injected into formations in connection with drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; (iv) require remedial measures to prevent or mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations. The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject, and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. Hazardous Substances and Handling Wastes 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 Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or the legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners or operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment, and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighbouring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We may generate materials in the course of our operations that may be regulated as hazardous substances. Water Discharges The Clean Water Act (the “CWA”) and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of hazardous substances, into state waters and waters of the United States (“WOTUS”). The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other CWA requirements and analogous state laws and regulations. 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. 15 Table of Contents The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening WOTUS or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations. Subsurface Injections 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. Air Emissions 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. 16 Table of Contents Regulation of GHG Emissions In response to findings in 2009 that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA, including rules requiring the monitoring and annual reporting of GHG emissions from large GHG emission sources in the U.S., including certain onshore and offshore natural gas, oil and NGL production sources, which include certain of our operations. An executive order, signed on January 20, 2025, instructed the EPA and other agency heads to brief the White House on the “legality and continuing applicability” of the 2009 endangerment findings. This could presage an attempt to void the 2009 findings, which, if successful, could result in voiding many of the EPA’s rules for GHG emissions. The EPA in July 2023 issued a proposed rule to expand the scope of its Greenhouse Gas Reporting Program for certain petroleum and natural gas facilities. The proposed rule would make the reach of the program both broader and more granular, creating reporting obligations for a wider set of methane and other gas emissions events and requiring increased technical detail for certain other preexisting reporting obligations. The rule was finalized in May of 2024 with an effective date of January 1, 2025. This rule could raise our costs of regulatory compliance. However, on September 12, 2025, the EPA proposed to permanently remove 46 source categories from GHG Reporting Program requirements and to otherwise delay reporting for onshore petroleum and natural gas production until 2034. 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. Although it is not possible at this time to predict how new laws or regulations that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas, oil and NGLs we produce and lower the value of our reserves. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our operations. 17 Table of Contents Hydraulic Fracturing Activities Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas, and NGLs from dense subsurface rock formations, and is used as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. For example, Colorado has promulgated rules that require oil and natural gas operators to disclose the volume of water and all chemicals used during the hydraulic fracturing process to an online registry. In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities. ESA and Migratory Birds The federal Endangered Species Act (“ESA”) and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. In June 2023, the Biden Administration announced proposed revisions concerning the procedures and criteria used for listing, reclassifying, and delisting protected species, and designating critical habitat. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases. OSHA 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. State Laws Our properties located in Colorado are subject to the authority of the CECMC, as well as other state agencies. Over the past several years, the CECMC has approved new rules regarding various matters, including wellbore integrity, hydraulic fracturing, well control, waste management, spill reporting, spacing of wells and pooling of mineral interests, and an increase in potential sanctions for CECMC rule violations. We do not believe that any of these CECMC rules will affect us in a way that materially differs from the way they will affect other oil and natural gas producers, gatherers, and marketers with which we compete. 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. 18 Table of Contents 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. On December 20, 2024, the CDPHE adopted new rules to reduce GHG emissions from midstream oil and gas operations that the agency touted as “first–of–its–kind.” Under these rules, midstream operators must capture and recover hydrocarbon emissions from activities such as pipeline pigging and blowdown of equipment. These new requirements may increase overall costs for the oil and gas industry in Colorado. It is possible that the CDPHE will propose additional rules to reduce emissions from other segments of the oil and gas sector. Related Permits and Authorizations Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other activities and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations. 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. Related Insurance We maintain insurance against some risks associated with above or underground contamination that may occur as a result of these activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. 19 Table of Contents Intellectual Property We do not currently own any intellectual property. Employees 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. Offices As of December 31, 2025, we have leased office space in Houston, Texas, where our principal office is located, and in Denver and Greeley, Colorado. Available Information, Website and Availability of Public Filings Our principal executive offices are located at 55 Waugh, Suite 400, Houston, Texas 77007. We also maintain an office in Denver, Colorado. Our website is located at www.prairieopco.com . We furnish or file our Annual Reports on Form 10–K, our Quarterly Reports on Form 10–Q, our Current Reports on Form 8–K and amendments to such reports and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. We also make these documents available free of charge at www.prairieopco.com under the “Investor Relations” link as soon as reasonably practicable after they are filed or furnished with the SEC. Information on our website is not incorporated into this Annual Report or our other filings with the SEC and is not a part of them. Our common stock is listed and traded on the Nasdaq Capital Market under the symbol “PROP.” Item 1A. Risk Factors 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 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, 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. Our risk factors can be broadly summarized by the following categories: ● Risks Related to our E&P Assets ● Risks Related to the Company ● Risks Related to the Ownership of our Common Stock While not an exhaustive list, the principal risks that we believe could adversely affect our business, financial condition, or results of operations include: ● There is no assurance that we will be able to successfully drill producing wells. If any of our assets are not commercially productive of crude oil or natural gas, any funds spent on exploration and production may be lost; ● 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; ● Oil, natural gas, and NGLs prices are highly volatile. An extended decline in commodity prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments; ● Our plan to develop and operate our existing and future E&P assets will require substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future; 20 Table of Contents ● 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 gas, and NGLs which could 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; ● Drilling for and producing oil and natural gas wells is a high–risk activity with many uncertainties that could adversely affect our business, financial condition, or results of operations; ● We intend to pursue the development of our properties in the DJ Basin through horizontal drilling and completion. Horizontal development operations can be more operationally challenging and costly relative to vertical drilling operations; ● Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities; ● Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage; ● Our future results of operations are highly dependent on our ability to find, develop, or acquire additional reserves; ● Our estimated oil, natural gas, 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; ● We will face strong competition from other oil and natural gas companies; ● Government regulation and liability for oil and natural gas operations may adversely affect our business and results of operations; ● All of our E&P assets are located in the DJ Basin, making us vulnerable to risks associated with operating primarily in a single geographic area; ● Our operations are subject to federal, state and local laws and regulations related to environmental and natural resources protection and occupational health and safety, which may expose us to significant costs and liabilities and result in increased costs and additional operating restrictions or delays. ● We have historically incurred significant losses, and may be unable to continuously generate profitability. Our ability to successfully operate and expand our business is dependent our ability to raise additional capital to support our drilling program on our existing assets; ● We will require significant additional capital to fund our growing operations; we may not be able to obtain sufficient capital and may be forced to limit the scope of our operations. ● We need to manage growth in operations to maximize our potential growth and achieve our expected revenues. Our failure to manage growth can cause a disruption of our operations that may result in the failure to generate revenues at levels we expect; ● We depend on the services of a small number of key personnel, and may not be able to operate and grow our business effectively if we lose their services or are unable to attract qualified personnel in the future, including as a result of recent leadership changes; ● Acquisitions, joint ventures or similar strategic relationships may disrupt or otherwise have a material adverse effect on our business and financial results; ● Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes–Oxley Act of 2002 could result in a restatement of our financial statements, cause investors to lose confidence in our financial statements and our Company and have a material adverse effect on our business and stock price; ● We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our cash flows; ● The shares of our Common Stock issuable upon conversion or exercise of, or as dividend payments on, as applicable, the outstanding Series D Preferred Stock, Series F Preferred Stock, Series D PIPE Warrants, Series E A Warrants, Exok Warrants, Subordinated Note Warrants, Series F Preferred Stock Warrants (if issued) and Merger Options could substantially dilute your investment and adversely affect the market price of our Common Stock; ● The Series F Preferred Stock may adversely affect the market price of our Common Stock; ● Our Board of Directors has broad discretion to issue additional securities, and in order to raise sufficient funds to expand our operations, we may have to issue securities at prices which may result in substantial dilution to our stockholders; ● If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Common Stock or if our operating results do not meet their expectations, our stock price could decline; ● We have not paid cash dividends in the past and do not expect to pay cash dividends in the foreseeable future. Any return on your investment may be limited to increases in the market price of our Common Stock. The foregoing factors should not be construed as exhaustive. This summary of risk factors should be read in conjunction with the more detailed risk factors below. 21 Table of Contents Risks Related to our E&P Assets There is no assurance that we will be able to successfully drill producing wells. If any of our assets are not commercially productive of crude oil or natural gas, any funds spent on exploration and production may be lost. There is no assurance that we will be able to obtain the requisite permits to continue successfully drilling producing wells. Some of our assets are not currently connected to the electrical grid or 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. If any of our assets are not economic, all of the funds that we have invested in such assets, or will invest in such assets, will be lost. In addition, the failure of our 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 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. As of December 31, 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 proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves as unproved reserves. Oil, natural gas, and NGLs prices are highly volatile. An extended decline in commodity prices may adversely affect our business, financial 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, 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. Prices for oil, natural gas, 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: ● the domestic and foreign supply of and demand for oil, natural gas, and NGLs; ● the price and quantity of foreign imports of oil, natural gas, and NGLs; ● the ability of and actions taken by the Organization of Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) and other oil–producing nations in connection with their arrangements to maintain oil prices and production controls; ● political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage; ● the proximity of our production to and capacity of oil, natural gas, and NGLs pipelines and other transportation and storage facilities; ● the level of consumer product demand; ● the value of the dollar relative to the currencies of other countries; ● the impact of energy consumption, supply, and conservation policies and activities by governmental authorities, international agreements, and non–governmental organizations to limit, restrict, suspend or prohibit the performance or financing of oil, natural gas, and NGLs exploration, production, development or marketing activities; ● U.S. and non–U.S. governmental regulations, including tariffs, environmental initiatives, and taxation; ● overall domestic and global economic conditions; ● the impact on worldwide economic activity of an epidemic, outbreak or other public health events; ● the price and availability of alternative fuels; ● technological advances affecting energy consumption, energy conservation and energy supply; ● stockholder activism or activities by non–governmental organizations to restrict the exploration, development and production of oil, natural gas, and NGLs to minimize emissions of carbon dioxide, a greenhouse gas; and ● weather conditions. 22 Table of Contents Our plan to develop and operate our existing and future E&P assets will require substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future. While we currently expect to develop and operate our existing and future E&P assets utilizing cash flow from operations, we may be unable to do so. Obtaining permits and approvals, seismic data, as well as exploration, development and production activities entail considerable costs, and, to the extent we are unable to fund such costs utilizing cash flow from operations, we may need to raise substantial additional capital, through future private or public equity offerings, strategic alliances or other alternative arrangements. Our future capital requirements will depend on many factors, including: ● the scope, rate of progress and cost of our exploration, appraisal, development and production activities; ● oil and natural gas prices; ● our ability to obtain the requisite permits and approvals to begin drilling, and potential litigation related to obtaining such permits and approvals; ● our ability to locate and acquire hydrocarbon reserves; ● our ability to produce oil or natural gas from those reserves; ● the terms and timing of any drilling and other production–related arrangements that we may enter into; ● the cost and timing of governmental approvals and/or concessions; and ● the effects of competition by larger companies operating in the oil and natural gas industry. If we raise additional capital through equity financing, the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we were to raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we are not successful in raising additional capital, we may be unable to continue our future exploration, development and production activities. 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 gas, and NGLs which could 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; 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–risk activity with many uncertainties that could adversely affect our business, financial condition, 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 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: ● unexpected drilling conditions; ● title problems; ● pressure or irregularities in formations; ● worker protection and workplace safety, including equipment failures or accidents; ● adverse weather conditions, such as winter storms and flooding, and changes in weather patterns including due to climate change; ● compliance with, or changes in, environmental laws and regulations relating to climate change, air emissions, hydraulic fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions and restrictions on drilling and completion operations, including as related to induced seismicity, and other laws and regulations, such as tax laws and regulations; 23 Table of Contents ● the availability and timely issuance of required governmental permits, approvals and licenses, or litigation concerning such permits, approvals and licenses; ● the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and related services, facilities and equipment to gather, process, compress, store, transport and market crude oil, natural gas and related commodities; ● compliance with environmental and other regulatory requirements; and ● environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline or tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the air, surface and subsurface environment. 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 pursue the development of our properties in the DJ Basin through horizontal drilling and completion. Horizontal development operations can be more operationally challenging and costly relative to vertical drilling operations. Horizontal drilling is generally more complex and more expensive on a per well basis than vertical drilling. As a result, there is greater risk associated with a horizontal well program. Risks associated with our horizontal drilling program include, but are not limited to, the following, any of which could materially and adversely impact the success of our horizontal drilling program and, thus, our cash flows and results of operations: ● successfully drilling and maintaining the wellbore to planned total depth; ● landing our wellbore in the desired hydrocarbon reservoir; ● effectively controlling the level of pressure flowing from particular wells; ● staying in the desired hydrocarbon reservoir while drilling horizontally through the formation; ● running our casing through the entire length of the wellbore; ● running tools and equipment consistently through the horizontal wellbore; ● successful design and execution of the fracture stimulation process; ● preventing downhole communications with other wells, or, in the alternative, disruption from non–simultaneous operations; ● successfully cleaning out the wellbore after completion of the final fracture stimulation stage; and ● designing and maintaining efficient forms of artificial lift throughout the life of the well. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity, or depressed natural gas and oil prices, the return on our investment in these areas may not be as attractive as anticipated. Further, as a result of any of these developments, we could incur material impairments of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future. Multi–well pad drilling and project development may result in volatility in our operating results. 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. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity. 24 Table of Contents Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities. 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. Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. 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 or an extension payment is not made prior to the expiration date of the lease, then approximately 14,300 net acres of our acreage will expire in 2026, approximately 4,200 net acres will expire in 2027, and approximately 8,200 net acres will expire in 2028 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 favourable 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, develop, or acquire additional reserves. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find, or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition, and results of operations would be materially and adversely affected. Our estimated oil, natural gas, 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 gas, and NGLs reserves. The process of estimating oil, natural 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 gas, and NGLs prices, subsurface characterization, production levels and operating and development costs. Our reserve estimates as of December 31, 2025 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, 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. To market our oil and natural gas production, we are dependent upon obtaining access to midstream infrastructure, including truck transportation, pipelines, transmission and/or storage and processing facilities. If we are unable to obtain such access on commercially reasonable terms or at all, we would be unable to market and sell our production and our business and financial position would be materially and adversely affected. The marketing of oil and natural gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, as well as the existence of adequate markets. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. We rely, and expect to rely in the future, on facilities developed and owned by third parties in order to store, process, transmit and sell our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could materially and adversely affect our ability to produce and market oil and natural gas. 25 Table of Contents 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. 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 fulfil 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–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, 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 face strong competition from other oil and natural gas companies. 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. Government regulation and liability for oil and natural gas operations may adversely affect our business and results of operations. 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. 26 Table of Contents All of our E&P assets are located in the DJ Basin, making us vulnerable to risks associated with operating primarily in a single geographic area. 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. Moreover, climate change may result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if facilities are subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may ultimately reduce demand for the products we provide. Such physical risks may also impact our suppliers, which may adversely affect our ability to provide our products. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured. Our operations are subject to federal, state and local laws and regulations related to environmental and natural resources protection and occupational health and safety, which may expose us to significant costs and liabilities and result in increased costs and additional operating restrictions or delays. 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. 27 Table of Contents 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. The general trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. Our oil and natural gas exploration, production, and development activities may be subject to a series of risks related to climate change and energy transition initiatives. 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–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–called non–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. 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. 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. 28 Table of Contents 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. 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 in such a case, regardless of the substance of the allegations, could have adverse reputational and financial impacts and an 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–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. 29 Table of Contents Our oil and natural gas exploration, production, and development activities may be subject to physical risks related to potential climate change impacts. Increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, wildfires, and floods and other climatic events, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to cause physical damage to our assets or those of our vendors and suppliers and could disrupt our supply chains, and thus could have an adverse effect on our business, financial position, operations and prospects. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or its production. While our operational consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality. Our business and ability to secure financing may be adversely impacted by increasing stakeholder and market attention to ESG matters. 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. 30 Table of Contents Restrictions and regulations regarding hydraulic fracturing could result in increased costs, delays and cancellations in our planned oil, natural gas, and NGLs exploration, production, and development activities. Our operations include hydraulic fracturing activities, which are 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 gas, 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 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. Additionally, we must dispose of the fluids produced during oil and natural gas production, including produced water. We may choose to dispose of produced water into deep wells by means of injection, either directly ourselves or through third party contractors. While we may seek to reuse or recycle produced water instead of disposing of such water, our costs for disposing of produced water could increase significantly as a result of increased regulation or if reusing and recycling water becomes impractical. Disposal wells are regulated pursuant to the UIC program established under the SDWA and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for construction and operation of such disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. 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. 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, and NGLs exploration and production operations and adversely affect the development and production of our reserves. The ESA and comparable state laws protect endangered and threatened species and their habitats. Under the ESA, the U.S. Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of species listed as threatened or endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act of 1918. Such designations could require us to develop mitigation plans to avoid potential adverse effects to protected species and their habitats, and our oil and natural gas operations may be delayed, restricted or prohibited in certain locations or during certain seasons, such as breeding and nesting seasons, when those operations could have an adverse effect on the species. Moreover, the future listing of previously unprotected species as threatened or endangered in areas where we are operating in the future could cause us to incur increased costs arising from species protection measures or could result in delays, restrictions or prohibitions on our planned development and production activities. 31 Table of Contents Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation. From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and natural gas companies. Such legislative changes have included, but have not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged with the enactment of the IRA, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and natural gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows. Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations. Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. In recent months, the uncertainty over such policies has caused substantial volatility in commodity, capital and financial markets, increased concerns over domestic and global inflation and adversely impacted consumer confidence in the U.S. and worldwide. Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and ultimately reduced demand for oil, natural gas, and NGLs. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, repurchases of securities or other capital requirements. Changes in tariffs and trade restrictions are outside of our control and can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes and tariffs, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations. Risks Related to the Company We have historically incurred significant losses, and may be unable to continuously generate profitability. Our ability to successfully operate and expand our business is dependent our ability to raise additional capital to support our drilling program on our existing assets. 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 . We will require significant additional capital to fund our growing operations; we may not be able to obtain sufficient capital and may be forced to limit the scope of our operations. We may not have sufficient capital to fund our future operations without significant additional capital investments, including the planned drilling of oil and natural gas wells. If adequate additional financing is not available on reasonable terms or at all, we may not be able to carry out our corporate strategy and we would be forced to modify our business plans (e.g., limit our growth, and/or decrease or eliminate capital expenditures), any of which may adversely affect our financial condition, results of operations and cash flow. Such reduction could materially adversely affect our business and our ability to compete. There can be no assurance that financing will be available in a timely manner or in amounts or on terms acceptable to us, or at all. 32 Table of Contents 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 . We may not be able to obtain additional financing on terms favourable to us, if at all. If we are unable to obtain adequate financing or financing on terms satisfactory to us when we require it, our ability to continue to support our business growth and respond to business challenges could be significantly impaired, and our business may be adversely affected. Our capital needs will depend on numerous factors, including, without limitation, our profitability, and the amount of our capital expenditures, including acquisitions. Moreover, the costs involved may exceed those originally contemplated. Failure to obtain intended economic benefits could adversely affect our business, financial condition and operating performances. We need to manage growth in operations to maximize our potential growth and achieve our expected revenues. Our failure to manage growth can cause a disruption of our operations that may result in the failure to generate revenues at levels we expect. In order to maximize potential growth, we may have to expand our operations. Such expansion will place a significant strain on our management and our operations. Our failure to manage our growth could disrupt our operations and ultimately prevent us from generating the revenues we expect. We depend on the services of a small number of key personnel, and may not be able to operate and grow our business effectively if we lose their services or are unable to attract qualified personnel in the future, including as a result of recent leadership changes. Our success depends in part upon the continued service of a small number of key personnel. They are critical to the overall management of the Company, and our strategic direction. We rely heavily on them because they have substantial experience with the Company and our business strategies. Our ability to retain them is therefore very important to our future success. We have employment agreements with our key personnel, but these employment agreements do not ensure that they will not voluntarily terminate their employment with us. 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. Past performance by members of the Company’s management team may not be indicative of the future performance of the Company. Past performance and operational experience of our management team and their affiliates is not a guarantee that we will be able to successfully develop and operate our assets or that the results of our acquisitions will be achieved. You should not rely on the historical record of our management team or their affiliates’ performance as indicative of the future performance of the Company or of an investment in our Common Stock. We will rely on key contracts and business relationships, and if our current or future business partners or contracting counterparties fail to perform or terminate any of their contractual arrangements with us for any reason or cease operations, or should we fail to adequately identify key business relationships, our business could be disrupted and our reputation may be harmed. 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. 33 Table of Contents Terrorist attacks, cyberattacks and threats could have a material adverse effect on our business, financial condition and results of operations. Terrorist attacks or cyberattacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Cyber incidents, including deliberate attacks, have increased in frequency globally. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the U.S. We depend on digital technology in many areas of our business and operations, including recording financial and operating data, oversight and analysis of our operations and communications with the employees supporting our operations and our customers or service providers. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. The secure processing, maintenance and transmission of information is critical to our operations, and we monitor our key information technology systems in an effort to detect and prevent cyberattacks, security breaches or unauthorized access. Despite our security measures, our information technology systems may undergo cyberattacks or security breaches including as a result of employee error, malfeasance or other threat vectors, which could lead to the corruption, loss, or disclosure of proprietary and sensitive data, misdirected wire transfers, and an inability to: perform services for our customers; complete or settle transactions; maintain our books and records; prevent environmental damage; and maintain communications or operations. Significant liability to the Company or third parties may result. We are not able to anticipate, detect or prevent all cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until an attack is already underway or significantly thereafter, and because attackers are increasingly using technologies specifically designed to circumvent cybersecurity measures and avoid detection. Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance. 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. The terms of our indebtedness and our Series F Preferred Stock may restrict our future business and operations. Our Credit Facility and Series F Preferred Stock Certificate of Designation (as defined below) contain covenants limiting our ability to pay dividends, incur indebtedness, grant liens, make acquisitions, make investments or dispositions, engage in transactions with affiliates and enter into hedging and derivative arrangements, as well as covenants requiring us to maintain certain financial ratios and tests. In addition, the borrowing base under the Credit Facility is subject to periodic review by the lenders. Difficulties in the credit markets may cause the banks to be more restrictive when redetermining the borrowing base. Our ability to pay interest and principal on our Credit Facility and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and borrowings or equity financing may not be available to pay or refinance such debt. If we are unable to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our debt on commercially reasonable terms, our business and financial condition could materially and adversely be affected. Acquisitions, joint ventures or similar strategic relationships may disrupt or otherwise have a material adverse effect on our business and financial results. As part of our strategy, we may explore strategic acquisitions and combinations, or enter into joint ventures or similar strategic relationships. These transactions are subject to the following risks: ● acquisitions, joint ventures or similar relationships may cause a disruption in our ongoing business, distract our management and make it difficult to maintain our standards, controls and procedures; ● we may not be able to integrate successfully the services, products, and personnel of any such transaction into our operations; ● we may not derive the revenue improvements, cost savings and other intended benefits of any such transaction; and ● there may be risks, exposures and liabilities of acquired entities or other third parties with whom we undertake a transaction, which may arise from such third parties’ activities prior to undertaking a transaction with us. Acquisitions may result in significant impairment charges and may operate at losses. We can provide no assurance that future acquisitions, joint ventures or strategic relationships will be accretive to our business overall or will result in profitable operations. 34 Table of Contents Our Charter provides for indemnification of officers and directors at our expense and limits their liability, which may result in a major cost to us and harm the interests of our stockholders because corporate resources may be expended for the benefit of officers and/or directors. Our Second Amended and Restated Certificate of Incorporation (our “Charter”) and applicable Delaware law provide for the indemnification of our directors and officers against attorney’s fees and other expenses incurred by them in any action to which they become a party arising from their association with or activities on our behalf. This indemnification policy could result in substantial expenditures by us that we will be unable to recoup. We have been advised that, in the opinion of the SEC, indemnification for liabilities arising under federal securities laws is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification for liabilities arising under federal securities laws, other than the payment by us of expenses incurred or paid by a director, officer or controlling person in the successful defense of any action, suit or proceeding, is asserted by a director, officer or controlling person in connection with the securities being registered, we will (unless in the opinion of our counsel, the matter has been settled by controlling precedent) submit to a court of appropriate jurisdiction, the question whether indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. The legal process relating to this matter, if it were to occur, is likely to be very costly and may result in us receiving negative publicity, either of which factors is likely to materially reduce the market and price for our shares if such a market ever develops. Future litigation or governmental proceedings could result in material adverse consequences to us, including judgments or settlements. From time to time, we may be involved in lawsuits, regulatory inquiries, governmental and other legal proceedings, such as title, royalty or contractual disputes, our oil and natural gas development activities, environmental liabilities, regulatory compliance matters, personal injury, property damage and employment litigation, in the ordinary course of our business. Many of these matters raise difficult and complicated factual and legal issues and are subject to uncertainties and complexities. The timing of the final resolutions to these types of matters is often uncertain. Additionally, the possible outcomes or resolutions to these matters could include adverse judgments or settlements, either of which could require substantial payments, adversely affecting our results of operations and liquidity. Irrespective of the outcome, legal proceedings or governmental investigations may adversely affect our business due to legal costs, diversion of resources and the attention of our management and employees, and other factors. Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes–Oxley Act of 2002 could result in a restatement of our financial statements, cause investors to lose confidence in our financial statements and our Company and have a material adverse effect on our business and stock price. 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. 35 Table of Contents The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of the Sarbanes–Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost–effective manner. 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: ● maintain a comprehensive compliance function; ● comply with rules promulgated by Nasdaq; ● continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; ● develop internal policies, such as those relating to insider trading; and ● involve and retain outside counsel and accountants in the above activities. Furthermore, we must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our annual reports on Form 10–K, including the requirement to have our independent registered public accounting firm attest to the effectiveness of our internal controls, unless we continue to be exempt from such requirement. Our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost–effective manner. We are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make our Common Stock less attractive to investors. 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 have utilized these exemptions and expect to continue to utilize these exemptions while we remain a smaller reporting company and non–accelerated filer. These exemptions and reduced disclosures in our SEC filings due to our status as a smaller reporting company mean our auditors do not review our internal control over financial reporting and may make it harder for investors to analyze our results of operations and financial prospects. We cannot predict if investors will find our Common Stock less attractive because we may rely on these exemptions. If some investors find our Common Stock less attractive as a result, there may be a less active trading market for our Common Stock and our stock prices may be more volatile. Our Charter and Bylaws designate the state and federal courts located within the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favourable judicial forum for disputes with us or our directors, officers, employees or agents. Our Charter and Amended and Restated Bylaws (“Bylaws”) provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery of the State of Delaware does not have jurisdiction, the Superior Court of the State of Delaware, or, if the Superior Court of the State of Delaware does not have jurisdiction, the U.S. District Court for the District of Delaware) will be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, other employee or agent or stockholder of the Company to the Company or the Company’s stockholders, (iii) any action against the Company arising pursuant to any provision of the DGCL or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware, or (iv) any action against the Company or any director, officer, other employee or agent of the Company asserting a claim governed by the internal affairs doctrine, including, without limitation, any action to interpret, apply, enforce or determine the validity of the Charter or the Bylaws, in each such case subject to such court’s having personal jurisdiction over the indispensable parties named as defendants therein. Our Charter and Bylaws further provide that, unless we consent in writing to the selection of an alternative forum, the federal district courts of the U.S. of America will be the sole and exclusive forum for the resolution of any complaint asserting a cause of action under the Securities Act. Our Charter and Bylaws provisions do not apply to complaints asserting a cause of action under the Exchange Act. A stockholder may not waive compliance with the federal securities laws and the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of the provisions of our Charter and Bylaws described in the preceding sentences. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favourable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Charter and Bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, or results of operations. 36 Table of Contents We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our cash flows. 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. Risks Related to the Ownership of our Common Stock The shares of our Common Stock issuable upon conversion or exercise of, or as dividend payments on, as applicable, the outstanding Series D Preferred Stock, Series F Preferred Stock, Series D PIPE Warrants, Series E A Warrants, Exok Warrants, Subordinated Note Warrants, Series F Preferred Stock Warrants (if issued), and Merger Options could substantially dilute your investment and adversely affect the market price of our Common Stock. Our Series D preferred stock with a par value of $0.01 and a stated value of $1,000 per share (“Series D Preferred Stock”), is convertible into shares of Common Stock at a price of $5.00 per share. At the time of the Series D Preferred Stock issuance, we also issued Series A warrants (“Series D A Warrants”) to purchase 3,475,250 shares of our Common Stock and Series B warrants (“Series D B Warrants” and together with the Series D A Warrants, the “Series D PIPE Warrants”) to purchase 3,475,250 shares of Common Stock (collectively, the “Series D PIPE”). 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. As of March 25, 2026, the outstanding shares of Series D Preferred Stock are convertible into an aggregate of 1,196,337 shares of Common Stock, the Series D PIPE Warrants are exercisable for an aggregate of 3,215,761 shares of Common Stock, the Series E A Warrants are exercisable for an aggregate of 4,000,000 shares of Common Stock, and the Series F Preferred Stock are convertible into an aggregate of 21,468,687 shares of Common Stock, assuming the standard conversion as set forth in the Prairie Operating Co. Certificate of Designation of Preferences, Rights and Limitations of Series F Convertible Preferred Stock (the “Series F Certificate of Designation”). Additionally, we have outstanding warrants which were issued in 2023 and provide the right to purchase 670,499 shares of Common Stock at $7.49 per share (the “Exok Warrants”). As of March 25, 2026, the Exok Warrants are exercisable for an aggregate of 5,019,163 shares of Common Stock and the Subordinated Note Warrants (as defined herein) are exercisable for an aggregate of 856,165 shares of Common Stock. In addition, there are also options outstanding to purchase an aggregate of 4,966,666 shares of Common Stock for $0.25 per share (the “Merger Options”), which are currently exercisable. Further, as described in the Series F Certificate of Designation and amended in the Series F Preferred Stock Warrant Amendment, the Series F Preferred Stock Warrants will be issuable on April 7, 2026 if, as of such date, the Series F Preferred Stock is outstanding and the per share trading price of our Common Stock is less than 115% of the conversion price of the Series F Preferred Stock. If issued, the Series F Preferred Stock Warrants will be exercisable for a number of shares of Common Stock equal to (i) 125% of the stated value of the Series F Preferred Stock divided by (ii) the volume weighted average per share trading price of the Common Stock for the 10–day period immediately preceding the issuance date of the Series F Preferred Stock Warrant. As of March 30, 2026, the Series F Preferred Stock Warrants have not been issued to the Series F Preferred Stockholder. Our stockholders may experience significant dilution if the Series F Preferred Stock Warrants are issued and subsequently exercised by the Series F Preferred Stockholder. 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. 37 Table of Contents Our stock price has fluctuated and been volatile in the past and may be volatile in the future, and as a result, investors in our Common Stock could incur substantial losses. Our stock price has fluctuated and been volatile in the past and may be volatile in the future. During the 12 months ended December 31, 2025, our Common Stock traded at a low of $1.57 per share and a high of $9.50 per share. We may continue to experience sustained depression or substantial volatility in our stock price in the foreseeable future unrelated to our operating performance or prospects. For the year ended December 31, 2025, we incurred a basic and diluted loss per common share of $1.35. As a result of this volatility, investors may experience losses on their investment in our Common Stock. The market price for our Common Stock may be influenced by many factors, including the following: ● further disagreements or price wars amongst OPEC+ members, including the effect thereof on global oil supply, oil storage capacity and oil prices; ● a domestic or global economic slowdown that could affect our financial results and operations and the economic strength of our customers; ● our ability to meet our working capital needs; ● quarterly variations in operating results; ● changes in financial estimates by us or securities analysts who may cover our stock or by our failure to meet the estimates made by securities analysts; ● changes in market valuations of other similar companies; ● announcements by us or our competitors of new products or of significant technical innovations, contracts, acquisitions, divestitures, strategic relationships or joint ventures; ● changes in laws or regulations applicable to our business; ● additions or departures of key personnel; ● changes in our capital structure, such as future issuances of debt or equity securities; ● short sales, hedging and other derivative transactions involving our capital stock; ● our limited public float and the relatively thin trading market for our Common Stock; ● transactions in our Common Stock, by directors, officers, affiliates and other major investors; and ● the other factors described under “Risk Factors” and “Cautionary Statement Regarding Forward–Looking Statements” included in this Annual Report. 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 Series F Preferred Stock may adversely affect the market price of our Common Stock. 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 dividends and amounts payable in the event of our liquidation, dissolution or winding–up of our affairs. 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. 38 Table of Contents Future sales of our Common Stock, or the perception that such future sales may occur, may cause our stock price to decline. Sales of substantial amounts of our Common Stock in the public market, or the perception that these sales may occur, could cause the market price of our Common Stock to decline. In addition, the sale of such shares, or the perception that such sales may occur, could impair our ability to raise capital through the sale of additional Common Stock or preferred stock. In addition, the number of shares of our Common Stock issuable upon conversion of, or as a dividend payment on, the Series F Preferred Stock and, if issued, upon exercise of the Series F Preferred Stock Warrant, may be substantial. The conversion price for the Series F Preferred Stock and, if issued, the exercise price for the Series F Preferred Stock Warrants will also be subject to certain anti–dilution, make–whole and/or other adjustments that will increase, potentially significantly, the number of shares of our Common Stock issuable upon conversion thereof. As of December 31, 2025, there were also outstanding options to purchase an aggregate of 4,966,666 shares of Common Stock for $0.25 per share, which are currently exercisable. The exercise of such options, and the conversion or exercise, as applicable, of our shares of preferred stock and warrants, including the Series F Preferred Stock and Series F Preferred Stock Warrants, could substantially dilute your investment and adversely affect the market price of our Common Stock. Following the closing of the Bayswater Acquisition, we registered the resale of the shares of our Common Stock received by Bayswater in the Bayswater Acquisition. Any sales of shares of our Common Stock by such holders, or expectations thereof, could similarly have the effect of depressing the market price for our Common Stock. Our Board of Directors has broad discretion to issue additional securities, and in order to raise sufficient funds to expand our operations, we may have to issue securities at prices which may result in substantial dilution to our stockholders. 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. If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Common Stock or if our operating results do not meet their expectations, our stock price could decline. The trading market for our Common Stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Common Stock or if our operating results do not meet their expectations, our stock price could decline. 39 Table of Contents Insiders have substantial control over the Company, and they could delay or prevent a change in our corporate control even if our other stockholders want it to occur. As of March 25, 2026, our executive officers and Board of Directors collectively beneficially own approximately 1.7% of our outstanding shares of Common Stock and the O’Neill Trust beneficially owns approximately 20.2%, of our outstanding shares of Common Stock. These stockholders are able to exercise significant control over all matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions. This could delay or prevent an outside party from acquiring or merging with our Company even if our other stockholders want it to occur. This may also limit your ability to influence the Company in other ways. In addition, certain investors own significant numbers of convertible securities, that if exercised or converted, could result in ownership of a significant portion of the outstanding shares of our Common Stock. For example, assuming full exercise or conversion, as applicable, of their respective convertible securities and no exercise or conversion by other security holders, certain holders could acquire a controlling position in our Common Stock. As of March 25, 2026, the outstanding shares of Series F Preferred Stock were convertible into an aggregate of 21,468,687 shares of our Common Stock, assuming the standard conversion set forth in the Series F Certificate of Designation and, the Series F Preferred Stockholder will have the right to convert the Series F Preferred Stock Warrant, if issued, into additional shares of our Common Stock. In addition, the exercise or conversion, as applicable, of the Series D Preferred Stock, Series D PIPE Warrants, and Series E A Warrants are subject to a beneficial ownership limitation of 4.99% of the outstanding shares of Common Stock, which may be increased by the holder upon written notice to us, to any specified percentage not in excess of 9.99%. The 9.99% beneficial ownership limitation may only be modified, amended or waived with the written consent of both the Company and the security holder. In November 2023, the O’Neill Trust entered into an agreement with us pursuant to which it amended the terms of each of its Series D PIPE Warrants and Series E A Warrants to increase the beneficial ownership limitation from 9.99% to 25% and gave notice to us that it was increasing its beneficial ownership limitation to 25% with respect to each of its remaining warrants. In August 2024, the O’Neill Trust entered into an agreement with us pursuant to which it, among other things, amended the terms of the Series D Preferred Stock to increase the beneficial ownership limitation from 9.99% to 49.9% and amended the terms of each of its Series D PIPE Warrants and Series E A Warrants to increase the beneficial ownership limitation from 25% to 49.9%. If the beneficial ownership limitations were to be amended or waived for other holders, certain holders would be able to convert their preferred shares or warrants for a significant portion of the outstanding shares of our Common Stock, and such holders would be able to exercise significant control over all matters requiring stockholder approval. We have not paid cash dividends in the past and do not expect to pay cash dividends in the foreseeable future. Any return on your investment may be limited to increases in the market price of our Common Stock. We have not paid any cash dividends on our Common Stock to date. We may retain future earnings, if any, for future operations, expansion and debt repayment and have no current plans to pay cash dividends for the foreseeable future. Any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, our results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors may deem relevant. In addition, our ability to pay dividends may be limited by covenants of any existing and future outstanding indebtedness we or our subsidiaries incur. Item 1B. Unresolved Staff Comments Not applicable. Item 1C. Cybersecurity Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks In the normal course of business, we may collect and store certain sensitive Company information, including proprietary and confidential business information, trade secrets, intellectual property, sensitive third–party information and employee information. We seek to assess, identify and manage cybersecurity risks through the processes described below: ● Risk Assessment : A system designed to protect and monitor data and cybersecurity risk has been implemented. Regular assessments of our cybersecurity safeguards and those of certain of our third–party service providers are conducted by independent firms. Our internal management team conducts regular evaluations designed to assess, identify and manage material cybersecurity risks, and we endeavour to update cybersecurity infrastructure, procedures, policies, and education programs in response. ● Incident Identification and Response: Monitoring and detection processes and procedures have been implemented to help identify cybersecurity incidents. In the event of an incident, we intend to follow protocols associated with incident detection, mitigation, recovery and notification, including notifying senior leadership and the Board of Directors, as appropriate. ● Cybersecurity Training and Awareness: Cybersecurity awareness training has been implemented for all employees whereby training is conducted on a monthly basis. ● Access Controls: Users are provided with access consistent with the principle of least privilege, which requires that users be given no more access than necessary to complete their job functions. ● Encryption and Data Protection : Encryption methods are used to protect sensitive data. We engage third–party service providers as part of our cybersecurity program. For example, we have engaged an independent cybersecurity advisor to review, assess, and make recommendations regarding our information security program and information technology strategic plan. We recognize that third–party service providers introduce cybersecurity risks. In an effort to mitigate these risks, we assess third party cybersecurity controls through the review of systems and organizational controls audit reports performed by independent auditors of certain of our information system related third–party service providers. The above cybersecurity risk management processes are integrated into the Company’s overall enterprise risk management program. Cybersecurity risks are understood to be significant business risks. 40 Table of Contents Impact of Risks from Cybersecurity Threats As of the date of this Annual Report, though the Company and our service providers have experienced certain cybersecurity incidents, we are not aware of any risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected or are reasonably likely to materially affect the Company , including its business strategy, results of operations or financial condition. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our information technology systems could have significant consequences to the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. Refer to Risk Factors – Terrorist attacks, cyberattacks and threats could have a material adverse effect on our business, financial condition and results of operations. for additional information about the risks to our business associated with a breach or compromise to our information technology systems. Board of Directors’ Oversight and Management’s Role Our Board of Directors is ultimately responsible for overseeing cybersecurity, information security, and information technology risks, as well as management’s actions to identify, assess, mitigate, and remediate those risks. As part of its program of regular risk oversight, the Audit Committee assists the Board of Directors in exercising oversight of the Company’s cybersecurity, information security, and information technology risks. On an annual basis, the Audit Committee reviews and discusses with management the Company’s policies, procedures and practices with respect to cybersecurity, information security and information and operational technology, including related risks. In addition, our Chief Financial Officer regularly briefs senior management, the Board of Directors and the Audit Committee on cybersecurity issues as part of our overall enterprise risk management program, which may include information regarding our exposure to privacy and cybersecurity risks deemed to have a moderate or higher business impact, even if immaterial to us. The Company has an internal management team that focuses on current and emerging cybersecurity matters. The Company’s internal management team is led by the Chief Financial Officer. The internal management team is responsible for implementing cybersecurity policies, programs, procedures, and strategies. Our internal management team includes professionals with backgrounds in information security, risk management, and incident response. Our Chief Financial Officer has experience leading the information technology departments at another upstream energy company for over four years and led enterprise risk management processes at an upstream energy company for approximately seven years. Item 2. Properties The information required by Item 2. is contained in Item 1. Business and is incorporated herein by reference. Item 3. Legal Proceedings The Company is not involved in any disputes and does not have any litigation matters pending which the Company believes could have a materially adverse effect on the Company’s financial condition or results of operations. There is no action, suit, proceeding, inquiry or investigation before or by any court, public board, government agency, self–regulatory organization or body pending or, to the knowledge of the executive officers of our Company or any of our subsidiaries, threatened against or affecting our Company, our Common Stock, any of our subsidiaries or of our Company’s or our Company’s subsidiaries’ officers or directors in their capacities as such, in which an adverse decision could have a material adverse effect. Item 4. Mine Safety Disclosures Not applicable. 41 Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market for Registrant’s Common Equity . Our Common Stock is quoted on the Nasdaq under the symbol “PROP.” Holders . As of March 25, 2026, there were approximately 264 record holders of our Common Stock. Because brokers and other institutions hold shares on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders. Dividends . We have not paid any cash dividends on our Common Stock to date. We may retain future earnings, if any, for future operations, expansion and debt repayment and have no current plans to pay cash dividends for the foreseeable future. Any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, our results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors may deem relevant. In addition, our ability to pay dividends may be limited by covenants of any existing and future outstanding indebtedness we or our subsidiaries incur. We do not anticipate declaring any cash dividends to holders of the Common Stock in the foreseeable future. Recent Sales of Unregistered Securities . None, other than as previously disclosed by the Company in a quarterly report on Form 10–Q or a current report on Form 8–K. Repurchases. None. Item 6 [Reserved] 42 Table of Contents Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations for the year ended December 31, 2025 and 2024 should be read in conjunction with our consolidated financial statements and related notes to those financial statements and other financial information appearing in this Annual Report. 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–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. Overview 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. Recent Developments Recent Acquisitions 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 acres. We funded the transaction by borrowing under our Credit Facility with Citi. Additionally, the assets we acquired in the Edge Acquisition include the fully permitted Simpson pad, which we began developing in August 2025, as well as seven other fully permitted locations. In August 2025, we completed the Third Exok Acquisition, acquiring approximately 5,000 net acres from Exok for $1.6 million. In October 2025, we entered into agreements to acquire certain assets from Summit and Crown for a total purchase price of $2.3 million payable in cash, subject to certain closing adjustments. The Summit and Crown Acquisitions included the acquisition of five operated wells on approximately 3,400 net acres. Bayswater Acquisition and Funding Transactions 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. 43 Table of Contents Drilling and Completion Activities 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. At–the–Market Offering 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. Series F Preferred Stock Warrants On March 25, 2026, we and the Series F Preferred Stockholder entered into the Series F Preferred Stock Warrant Amendment, which, among other things, changes the issuance 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. Additionally, the Series F Preferred Stock Warrant Amendment provides that we will pay the Series F Preferred Stockholder an aggregate amount equal to $3.0 million on April 6, 2026, unless the obligation to pay such fee has been waived by the Series F Preferred Stockholder in their sole discretion. Factors Affecting the Comparability of Financial Results Commodity Prices Since oil, natural gas, and NGL prices are the most significant factors impacting our results of operations, continued price variations can have a material impact on our financial results and capital expenditures. 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, natural gas, and NGL prices on our cash flows from operations. However, our hedging activity could reduce our ability to benefit from increases in oil, natural gas, and NGL prices. Further, we could sustain hedge losses to the extent our oil, natural gas, and NGL derivative contract prices are lower than market prices and, conversely, we could recognize gains to the extent our oil, natural gas, and NGL derivative contract prices are higher than market prices. Refer to Results of Operations – Other income and expenses below for a discussion of our recognized gains or losses on derivative contracts. 44 Table of Contents As of December 31, 2025, 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: Settling January 1, 2026 through December 31, 2026 Settling January 1, 2027 through December 31, 2027 Settling January 1, 2028 through December 31, 2028 Crude Oil Swaps: Notional volume (Bbls) 4,230,866 3,306,753 1,515,007 Weighted average price ($/Bbl) $ 62.36 $ 62.03 $ 61.60 Natural Gas Swaps: Notional volume (MMBtus) 13,420,634 11,882,126 4,406,357 Weighted average price ($/MMBtu) $ 4.08 $ 4.07 $ 4.00 Ethane Swaps: Notional volume (Bbls) 288,956 232,375 51,809 Weighted average price ($/Bbl) $ 11.54 $ 11.05 $ 11.28 Propane Swaps: Notional volume (Bbls) 509,724 417,744 94,220 Weighted average price ($/Bbl) $ 26.36 $ 26.51 $ 26.00 Iso Butane Swaps: Notional volume (Bbls) 63,185 50,812 11,328 Weighted average price ($/Bbl) $ 33.92 $ 30.22 $ 29.63 Normal Butane Swaps: Notional volume (Bbls) 174,809 140,580 31,343 Weighted average price ($/Bbl) $ 35.24 $ 31.37 $ 30.37 Pentane Plus Swaps: Notional volume (Bbls) 130,321 104,802 23,366 Weighted average price ($/Bbl) $ 53.05 $ 52.40 $ 52.49 Recent Acquisitions 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 acres and funded the transaction by borrowing under our Credit Facility. In August 2025, we completed the Third Exok Acquisition, acquiring approximately 5,000 net acres for $1.6 million. In October 2025, we entered into agreements to acquire certain assets from Summit and Crown for a total purchase price of $2.3 million, subject to certain closing adjustments, payable in cash. The Summit and Crown Acquisitions included the acquisition of five operated wells on approximately 3,400 net acres. Bayswater Acquisition As discussed above, we closed the Bayswater Acquisition on March 26, 2025, for total cash consideration $482.5 million, $15.0 million of which was deposited in escrow pending the completion of the Additional Working Interest Acquisition, which Bayswater acquired and assigned to us on April 11, 2025, and we issued the Equity Consideration to Bayswater. We completed the final settlement with Bayswater on October 15, 2025, which resulted in total consideration of $475.6 million. NRO Acquisition 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 NRO 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”) to YA II PN, LTD., a Cayman Islands exempt limited company (“Yorkville”). Crypto Sale We acquired cryptocurrency mining operations in May 2023. On January 23, 2024, we sold all of our cryptocurrency miners for consideration consisting of (i) $1.0 million in cash and (ii) $1.0 million in deferred cash 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 cryptocurrency miners 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 cryptocurrency miners until the aggregate amount of such payments equals the Deferred Purchase Price, plus accrued interest (collectively, the “Crypto Sale”). In July 2025, we received $0.4 million to satisfy the remaining Deferred Purchase Price note receivable. 45 Table of Contents Results of Operations Revenue, Production, and Average Realized Price The following table presents the components of our revenue, production, and average realized sales price for the years indicated: Year Ended December 31, 2025 (1) 2024 Revenues (in thousands) Crude oil sales $ 204,040 $ 6,595 Natural gas sales 9,472 551 NGL sales 28,136 793 Total revenues $ 241,648 $ 7,939 Production: Oil (MBbls) 3,406 96 Natural gas (MMcf) 10,753 245 NGL (MBbls) 1,550 33 Total production (MBoe) (2) 6,748 170 Average sales volumes per day (Boe/d) 18,487 464 Average sales price (excluding effects of derivatives): Oil (per MBbls) $ 59.91 $ 68.60 Natural gas (per MMcf) $ 0.88 $ 2.25 NGL (per MBbls) $ 18.16 $ 24.03 Average price (per MBoe) $ 35.81 $ 46.70 Average sales price (including effects of derivatives): Oil (per MBbls) $ 63.87 $ 68.60 Natural gas (per MMcf) $ 1.65 $ 2.25 NGL (per MBbls) $ 17.93 $ 24.03 Average price (per MBoe) $ 38.98 $ 46.70 (1) Total revenues and production for the year ended December 31, 2025, include revenue and production volumes from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. (2) MBoe is calculated using six MMcf of natural gas equivalent to one MBbl of oil. Revenue and Production. For the year ended December 31, 2025, the majority of our total production volumes and revenues 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 revenue from the Bayswater Acquisition from March 26, 2025 through December 31, 2025. All of our production volumes and revenues for the year ended December 31, 2024 were 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. Operating expenses The following table presents the components of our operating expenses for the years indicated: Year Ended December 31, 2025 (1) 2024 (In thousands, except per Boe amounts) Lease operating expenses $ 41,411 $ 1,265 Transportation and processing 8,910 864 Ad valorem and production taxes 21,231 591 Depreciation, depletion, and amortization 48,916 427 Accretion of asset retirement obligation 247 6 Exploration expenses 1,332 734 Abandonment and impairment of unproved properties 3,409 — General and administrative expenses (2) 50,614 30,565 Total operating expenses $ 176,070 $ 34,452 Operating expenses per Boe: Lease operating expenses $ 6.14 $ 7.44 Transportation and processing 1.32 5.08 Ad valorem and production taxes 3.15 3.48 Depreciation, depletion, and amortization 7.25 2.51 Accretion of asset retirement obligation 0.04 0.04 Exploration expenses 0.20 4.31 Abandonment and impairment of unproved properties 0.51 — General and administrative expenses (2) 7.50 179.80 Total operating expenses $ 26.11 $ 202.66 (1) Total operating expenses for the year ended December 31, 2025, include operating expenses for the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. Operating expenses per Boe for the year ended December 31, 2025 are calculated over production volumes which include volumes from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. (2) General and administrative expenses for the years ended December 31, 2025 and 2024 include non–cash long–term incentive compensation expenses of $14.8 million and $8.4 million, respectively. 46 Table of Contents Lease operating expenses . For the year ended December 31, 2025, lease operating expenses (“LOE”) increased $40.1 million compared to the year ended December 31, 2024. The increase in LOE was primarily driven by increased production as a result of the Bayswater Acquisition, which closed on March 26, 2025. We did not incur any LOE prior to the closing of the NRO Acquisition on October 1, 2024. Transportation and processing expenses . For the year ended December 31, 2025, transportation and processing expenses increased $8.0 million compared to the year ended December 31, 2024. This increase was primarily attributable to increased production driven by the Bayswater Acquisition, which closed on March 26, 2025. We did not incur any transportation and processing expenses prior to the closing of the NRO Acquisition on October 1, 2024. Ad valorem and production taxes . For the year ended December 31, 2025, ad valorem and production taxes increased $20.6 million compared to the year ended December 31, 2024. The increase in ad valorem and production taxes was primarily driven by increased production as a result of the Bayswater Acquisition, which closed on March 26, 2025. We did not incur any ad valorem and production taxes prior to the closing of the NRO Acquisition on October 1, 2024. Depreciation, depletion, and amortization . For the year ended December 31, 2025, depreciation, depletion, and amortization (“DD&A”) expenses increased $48.5 million, compared to the year ended December 31, 2024. The increase in DD&A was largely attributable to increased production as a result of the Bayswater Acquisition, which closed on March 26, 2025, and our new drills which came online in the second half of 2025. We did not recognize any DD&A related to oil and natural gas properties prior to the closing of the NRO Acquisition on October 1, 2024. 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. General and administrative expenses. For the year ended December 31, 2025, general and administrative expenses increased $20.0 million compared to the year ended December 31, 2024. This increase was partially attributable to incremental payroll expenses of $8.2 million and non–cash stock–based compensation expenses of $6.3 million, driven by increased headcount following the Bayswater Acquisition. Additionally, insurance, rent, and vehicle expense increased by $2.3 million following the Bayswater Acquisition and we incurred $1.6 million of transition service agreement costs for the 6–month period following the close of the Bayswater Acquisition. Other expenses The following table presents the components of our other expenses for the years indicated: Year Ended December 31, 2025 2024 (In thousands) Interest expense $ (28,521 ) $ (1,142 ) Gain (loss) on derivatives, net 79,230 (4,395 ) Loss on adjustment to fair value – embedded derivatives, debt, and warrants (63,341 ) (5,358 ) Loss on issuance of debt — (3,039 ) Interest income and other 759 580 Other expenses $ (11,873 ) $ (13,354 ) 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. Gain (loss) on derivatives, net. For the year ended December 31, 2025, gain on derivatives, net was $79.2 million compared to a loss on derivatives, net of $4.4 million for the year ended December 31, 2024. The change in gain (loss) on derivatives, net was primarily due to a $62.2 million increase in unrealized gain on derivatives driven by favourable changes in the fair value of our open derivative contracts as of December 31, 2025. Additionally, our realized gain on derivatives increased by $21.4 million for the year ended December 31, 2025 due to favourable changes in cash settlements during the period compared to the year ended December 31, 2024. Refer to Factors Affecting the Comparability of Financial Results – Commodity Prices above for a further discussion of our derivative contracts. 47 Table of Contents 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. Interest income and other. For the year ended December 31, 2025, interest income and other increased $0.2 million compared to the year ended December 31, 2024, primarily driven by higher average cash balances in the current period. Income tax expense For the year ended December 31, 2025, we recognized deferred income tax expense of $21.7 million, resulting in an effective tax rate of 40.3%. We did not recognize any income tax expense for the year ended December 31, 2024. The overall change in our effective tax rate for the year ended December 31, 2025 compared to the year ended December 31, 2024 is primarily driven by the removal of a previously recorded valuation allowance resulting from cumulative income and positive evidence that these tax attributes are now more–likely–than–not realized. Discontinued operations The following table presents the components of our net loss from discontinued operations for the years indicated: Year Ended December 31, 2025 2024 (In thousands) Cryptocurrency mining revenue $ — $ 193 Cryptocurrency mining costs — (55 ) Depreciation and amortization — (102 ) Impairment of cryptocurrency mining equipment — — Loss from sale of cryptocurrency mining equipment — (1,081 ) Loss from discontinued operations before income taxes — (1,045 ) Income tax expense — — Net loss from discontinued operations $ — $ (1,045 ) For the year ended December 31, 2025, the net loss from discontinued operations decreased $1.0 million compared to the year ended December 31, 2024. As discussed above, we completed the Crypto Sale in January 2024; therefore, we only had cryptocurrency mining revenue or related expenses during a portion of the year ended December 31, 2024. However, we recognized a $1.1 million loss on the sale of cryptocurrency mining equipment. Refer to Factors Affecting the Comparability of Financial Results – Crypto Sale above for a further discussion of the Crypto Sale. Non–GAAP Financial Measures Adjusted EBITDA and PV–10 are financial measures not calculated or presented in accordance with generally accepted accounting principles (“GAAP”). These supplemental non–GAAP financial measures are used by management and external users of our financial statements, such as investors, lenders, and rating agencies and may not be comparable to similarly titled measures reported by other companies. Adjusted EBITDA Adjusted EBITDA is used by management to evaluate the performance of our business, make operational decisions, and assess our ability to generate cashflows. Management believes Adjusted EBITDA provides investors with helpful information to better understand the underlying performance trends of our business, facilitate period–to–period comparisons, and assess the company’s operating results. 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. 48 Table of Contents The following table presents the reconciliation of Net income (loss) from continuing operations to Adjusted EBITDA for the years indicated: Year Ended December 31, 2025 (1) 2024 (In thousands) Net income (loss) from continuing operations reconciliation to Adjusted EBITDA: Net income (loss) from continuing operations $ 32,051 $ (39,867 ) Adjustments: Depreciation, depletion, and amortization 48,916 427 Accretion of asset retirement obligations 247 6 Abandonment and impairment of unproved properties (2) 3,409 — Non–cash stock–based compensation 14,764 8,377 Interest expense, net 27,471 562 Non–cash loss on adjustment to fair value – embedded derivatives, debt, and warrants (3 63,341 5,358 Non– cash loss on issuance of debt (4) — 3,039 Unrealized (gain) loss on derivatives (57,834 ) 4,395 Litigation settlement expense 1,516 — Income tax expense (5) 21,654 — Adjusted EBITDA $ 155,535 $ (17,703 ) (1) Net income (loss) from continuing operations for the year ended December 31, 2025 includes revenue and related expenses attributable to the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. (2) Reflects the abandonment of unproved locations which we have deemed non–core and allowed to expire. (3) Reflects the changes in the fair values of the financial instruments measured at fair value on a recurring basis. Refer to Liquidity and Capital Resources – Significant Sources of Liquidity below for a further discussion. (4) Reflects the loss recognized for the issuance of the Subordinated Note and the Subordinated Note Warrants in the third quarter of 2024. Refer to Liquidity and Capital Resources – Significant Sources of Liquidity below for a further discussion. (5) Reflects deferred income tax expense recognized for the year ended December 31, 2025. PV–10 PV–10 is a financial measure not presented in accordance with U.S. GAAP. PV–10 is derived from the 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 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 a 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. While the standardized measure is dependent on the unique tax situation of each company, PV–10 is based on prices and discount factors that are consistent for all companies. 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 presents the reconciliation of the Standardized Measure to the PV–10 of our estimated proved reserves for the years indicated: Year Ended December 31, 2025 2024 (In thousands) Standardized Measure $ 851,702 $ 255,142 Present value of future income taxes discounted at 10% 368,112 48,017 PV–10 $ 1,219,814 $ 303,159 Liquidity and Capital Resources Overview 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. 49 Table of Contents 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. Our development program is dependent upon our cash flow from operations generated from our assets and our ability to obtain additional financing through our Credit Facility. Additionally, we could obtain additional financing through public and private capital markets; however, the availability of additional capital would be subject to numerous factors outside of our control including prices of oil and natural gas and the overall health of the U.S. and global economic environments. There can be no assurance that we will be able to obtain such additional capital. The amount and allocation of future capital expenditures will depend upon a number of factors, including the amount and timing of cash flows from operations, investing and financing activities, and the timing and cost of additional capital sources. We currently plan to be the operator on substantially all of our acreage. As a result, we anticipate that the timing and level of our capital spending will largely be discretionary and within our control. We could choose to defer a portion of our planned capital expenditures depending on a variety of factors, including, but not limited to, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs, the level of participation by other working interest owners, the success of our drilling activities, prevailing and anticipated prices for oil, natural gas, and NGLs, and the availability of necessary equipment, infrastructure and capital. Working Capital We define working capital as current assets less current liabilities. As of December 31, 2025, we had a working capital deficit of $46.1 million and cash and cash equivalents of less than $0.1 million. As of December 31, 2024, we had a working capital deficit of $44.7 million and cash and cash equivalents of $5.2 million. Cash Flows from Operating, Investing, and Financing Activities The following table summarizes our cash flows for the years indicated: Year Ended December 31, 2025 2024 (In thousands) Net cash provided by (used in) operating activities $ 153,902 $ (9,348 ) Net cash used in investing activities (655,916 ) (83,408 ) Net cash provided by financing activities 496,842 84,911 Net decrease in cash and cash equivalents (5,172 ) (7,845 ) Cash and cash equivalents, beginning of the year 5,192 13,037 Cash and cash equivalents, end of the year $ 20 $ 5,192 Operating activities. Net cash provided by operating activities totalled $153.9 million for the year ended December 31, 2025, compared to cash used in operating activities of $9.3 million for the year ended December 31, 2024. The $163.3 million change in our net cash provided in operating activities was largely due to an increase in revenue recognized during the current period, partially offset by increased operating costs during the current period. Investing activities. Net cash used in investing activities totalled $655.9 million and $83.4 million during the years ended December 31, 2025 and 2024, respectively. The $572.5 million increase in our net cash used in investing activities was largely driven by cash paid for the Bayswater Acquisition of $459.6 million. Additionally, our expenditures for the development of oil and natural gas properties increased $149.2 million during year ended December 31, 2025 compared to the year ended December 31, 2024. 50 Table of Contents Financing activities. Net cash provided by financing activities totalled $496.8 million for the year ended December 31, 2025, driven by $43.8 million from the issuance of Common Stock, net of related issuance costs of $3.9 million, $148.3 million from the issuance of the Series F Preferred Stock, net of related issuance costs of $12.2 million, $390.0 million from borrowings under the Credit Facility, net of related issuance costs of $14.1 million, offset with $52.0 million in repayments, and $0.6 million of cash received for option exercises during the period. These increases were partially offset by a $3.2 million repayment of the Subordinated Note. Net cash provided by financing activities totalled $84.9 million for the year ended December 31, 2024, driven by proceeds of $33.5 million from the exercise of Series D B and Series E B Warrants (as defined herein) throughout the year, $28.0 million from borrowings under the Credit Facility, net of related issuance costs of $0.3 million, $15.0 million of proceeds from the issuance of Common Stock, net of related issuance costs of $5.0 million, $14.3 million of proceeds from the issuance of the Senior Convertible Note, partially offset by a repayment of $3.8 million, and $5.0 million of proceeds from the issuance of the Subordinated Note, partially offset by a repayment of $1.8 million. Significant Sources of Liquidity 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 the Credit Facility, 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, which added Bank of America N.A. and West Texas National Bank as lenders under the Credit Facility. The Credit Facility is scheduled to mature on March 26, 2029, and provides for a maximum credit commitment of $1.0 billion. As of December 31, 2025, the Credit Facility had a borrowing base of $475.0 million and an aggregate elected commitment of $475.0 million. The Credit Facility includes a $47.5 million sublimit for the issuance of letters of credit. The borrowing base is subject to semi–annual redeterminations based upon the value of our oil and gas properties as determined in a reserve report immediately preceding January 1st and July 1st of each year, subject to certain interim redeterminations. The borrowing base of $475.0 million was reaffirmed with the mid–year 2025 redetermination. 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. Standby Equity Purchase Agreement. On September 30, 2024, we entered into the SEPA with Yorkville, whereby, subject to certain conditions, we have the right, but not the obligation, to sell to Yorkville up to $40.0 million shares of Common Stock, at any time and in an amount as specified in the Company’s request (“Advance Notice”), during the commitment period commencing on September 30, 2024 (the “SEPA Effective Date”) and terminating on September 30, 2026. Each issuance and sale by us under the SEPA (each, an “Advance”) is subject to a maximum limit equal to 100% of the aggregate volume traded of our Common Stock on the Nasdaq Stock Market during the five trading days immediately prior to the date of the Advance Notice. The shares will be issued and sold to Yorkville at a per share price equal to 97% of the lowest daily volume weighted average price of Common Stock for three consecutive trading days commencing on the trading day immediately following Yorkville’s receipt of an Advance Notice. On September 30, 2024, pursuant to the SEPA, we paid Yorkville a structuring fee of $25,000 and a commitment fee of 100,000 shares of Common Stock. Pursuant to the SEPA, we may issue up to a total of 4,198,343 shares of Common Stock within the cap of 19.99% of our issued and outstanding Common Stock as of the SEPA Effective Date through Advances under the SEPA, upon conversion of the Senior Convertible Note or through any other issuances of Common Stock thereunder. However, per the Series F Certificate of Designation, we may only request an Advance Notice on the SEPA if the Series F Preferred Stock is fully converted or redeemed. 51 Table of Contents 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. Senior Convertible Note. On September 30, 2024, Yorkville advanced an initial of $15.0 million (the “Pre–Paid Advance”) to us, and we issued the Senior Convertible Note to Yorkville, with an interest rate of 8.00% and a maturity date of September 30, 2025. Yorkville had the option to convert the Pre–Paid Advance into shares of Common Stock at any time at the conversion price set forth in the Senior Convertible Note agreement. We had the option, at any time, to redeem all or a portion of the amounts outstanding under the Senior Convertible Note at 105% of the principal amount thereof, plus accrued and unpaid interest. Additionally, we had the option to convert the Pre–Paid Advance into shares of Common Stock at any time at the conversion price set forth in the Senior Convertible Note agreement, however, a conversion requested by us would not result in us receiving cash but instead would be applied towards reducing the outstanding balance of the Senior Convertible Note. On the issuance date of the Senior Convertible Note, we determined that certain features of the Senior Convertible Note required bifurcation and separate accounting as embedded derivatives and elected the fair value option to account for the Senior Convertible Note; therefore, in accordance with ASC 815, we recorded the Senior Convertible Note at fair value. In December 2024, we made a $3.7 million payment on the Senior Convertible Note, resulting in a principal balance of $11.3 million as of December 31, 2024. However, due to the election of the fair value option, we reported the Senior Convertible Note at its fair value of $12.6 million on our consolidated balance sheet as of December 31, 2024. During the first quarter of 2025, Yorkville converted the remaining $11.3 million of the Senior Convertible Note in exchange for 2.1 million shares of Common Stock, resulting in a principal balance of $0 as of December 31, 2025. As a result, we recognized a loss on adjustment to fair value – embedded derivatives, debt, and warrants of $5.5 million 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. Pursuant to the terms of the Subordinated Note, we issued the Subordinated Note Warrants to purchase up to 1,141,552 shares of Common Stock to the Noteholders, which vest in tranches based on the date of repayment of the Subordinated Note. As of December 31, 2025 and 2024, Subordinated Note Warrants providing the right to purchase 856,165 shares and 570,778 shares, respectively, of Common Stock had vested and were outstanding. At the time of issuance, we determined that certain features of the Subordinated Note and the Subordinated Note Warrants required bifurcation and separate accounting as embedded derivatives and elected the fair value option to account for the Subordinated Note and the Subordinated Note Warrants; therefore, in accordance with ASC 815, we recorded the Subordinated Note and the Subordinated Note Warrants at fair value and remeasured the fair value each reporting period with changes in fair value recognized in earnings. As of December 31, 2024, the fair value of the Subordinated Note was $4.6 million. On March 26, 2025, in connection with the closing and financing of the Bayswater Acquisition, we paid $3.2 million of the outstanding balance under the Subordinated Note. Pursuant to the terms of the payoff letter, we and the Noteholders agreed that the remaining $1.5 million outstanding Subordinated Note balance would be converted to principal, will accrue interest at a rate of 15% of per annum, and all principal and other amounts owed (other than interest) pursuant to the Subordinated Note will not be redeemable for any reason while any of the Series F Preferred Stock remain outstanding. Therefore, we determined that changes to the Subordinated Note included in the payoff letter qualify as an extinguishment of debt and elected to forgo the previous fair value option election. As such, we now present the Subordinated Note at its face value of $1.5 million as of December 31, 2025. 52 Table of Contents Series F Preferred Stock and Series F Preferred Stock Warrants. On March 24, 2025, we entered into a securities purchase agreement with the Series F Preferred Stockholder, pursuant to which the Series F Preferred Stockholder agreed to purchase for an aggregate of $148.3 million (i) 148,250 shares of Series F Preferred Stock, with a stated value of $1,000 per share (the “Stated Value”), convertible into shares of Common Stock and (ii) the Series F Preferred Stock Warrants to purchase shares of Common Stock, subject to the satisfaction of certain conditions. The Series F Preferred Offering closed on March 26, 2025, and we received approximately $136.1 million of net proceeds, after deducting advisor fees and offering expenses. We used the proceeds from the Series F Preferred Offering to fund a portion of the Bayswater Acquisition, which closed on March 26, 2025. On March 25, 2026, we and the Series F Preferred Stockholder entered into 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. The Series F Preferred Stockholder is entitled to receive, on a cumulative basis, dividends on each share of Series F Preferred Stock at a rate per annum equal to 12%, payable in cash on March 1, June 1, September 1 and December 1 of each calendar year, which began on June 1, 2025. Alternatively, according to the Series F Certificate of Designation, we may elect to pay the dividends entirely or partially in shares of Common Stock. Additionally, the Series F Certificate of Designation states that six months after the anniversary date of the maturity of our Credit Facility the dividend rate will increase to 25%. We elected to pay the June 1, September 1, and December 1, 2025 dividends by issuing the Series F Preferred Stockholder 1,305,000, 1,806,000, and 2,421,000 shares, respectively, of Common Stock. The Series F Preferred Stockholder may convert all or a portion its shares of Series F Preferred Stock into shares of Common Stock at any time at a standard conversion rate of 202.0202 shares of Common Stock per share of Series F Preferred Stock, subject to certain adjustments as described in the Series F Certificate of Designation. The Series F Preferred Stockholder also has the option to convert all or a portion of its shares of Series F Preferred Stock using an Alternative Conversion Rate (as defined in the Series F Certificate of Designation) in lieu of the conversion rate, subject to an Alternative Conversion Cap (as defined in the Series F Certificate of Designation) for each quarter. During the year ended December 31, 2025, 27,200 shares of Series F Preferred Stock were converted into 13,024,200 shares of Common Stock using the Alternative Conversion Rate. 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. We currently anticipate any 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. Liquidity Analysis For the year ended December 31, 2025, we had a net loss attributable to Prairie Operating Co.’s common stockholders of $60.9 million. We cannot predict if we will be able to sustain profitability on a quarterly or annual basis and extended periods of losses and negative cash flow may prevent us from successfully operating and expanding our business. As of December 31, 2025, we had cash and cash equivalents of less than $0.1 million, a working capital deficit of $46.1 million, and an accumulated deficit of $87.7 million. 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. Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations is based upon the accompanying consolidated financial statements. These financial statements have been prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reports for assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Management believes its estimates and assumptions to be reasonable under these circumstances. Certain estimates and assumptions are inherently unpredictable and actual results could differ from those estimates. Described below are the most significant policies and the related estimates and assumptions used by management in the preparation of our financial statements. Refer to Item 8. Financial Statements and Supplementary Data – Note 2 – Summary of Significant Accounting Policies for a further discussion of our accounting policies. Oil and Natural Gas Properties 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. 53 Table of Contents We assess proved properties for impairment whenever circumstances indicate that the carrying value of proved oil and natural gas properties may not be recoverable. During the assessment, we compare unamortized capitalized costs to the expected undiscounted pre–tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre–tax future cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in ASC Topic 820 , Fair Value Measurements . If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market–based weighted average cost of capital. Any impairments would be booked in the period they were identified. Additionally, we expense any costs related to the expiration of unproved leasehold. During the year ended December 31, 2025, we recorded $3.4 million related to leases which expired, which is presented as abandonment and impairment of unproved properties expense on its consolidated statement of operations. We did not record any abandonment and impairment of unproved properties expense for the year ended December 31, 2024. 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. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil, natural gas, and NGL prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered. If our estimates of proved reserve decline, the rate at which we record depletion expense would increase, which would reduce future net income. Any changes in the depletion rate calculations caused by changes in reserve estimates would be made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Standardized Measure of Discounted Net Future Cash Flows. The Standardized Measure is the present value, discounted at 10%, of estimated future net cash flows to be generated from the production of proved reserves calculated by using the 12–month unweighted arithmetic average of the first–day–of–the–month price for each month in the period January through December (with consideration of price changes only to the extent provided by contractual arrangements). The estimated future net cash flows are reduced by projected future development, production (excluding DD&A and any impairments of oil and natural gas properties), plug and abandonment costs, and estimated future income tax expenses. The Standardized Measure is calculated per ASC Topic 932, Extractive Activities – Oil and Gas and in accordance with SEC pricing guidelines. Although our estimates of total proved reserves, development costs, and production rates are based on the best available information, the development and production of the oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from our estimates. Therefore, the Standardized Measure should not be considered to represent our estimate of expected revenues or the fair value of our proved oil, natural gas, and NGL reserves. Asset acquisitions . As part of our business strategy, we seek to complete several asset acquisitions each year. We typically account for these acquisitions under the acquisition method of accounting. As such, we recognize amounts for identifiable assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market—based weighted average cost of capital rate. 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. Series F Preferred Stock Embedded Derivatives and Series F Preferred Stock Warrants at Fair Value 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. Additionally, we have determined that the Series F Preferred Stock Warrants are not considered indexed to our own stock because 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. As such, we have determined that the Series F Preferred Stock Warrants should be accounted for as liabilities pursuant to ASC Topic 480, Distinguishing Liabilities from Equity (“ASC 480”). We engaged a third–party valuation expert to assist in preparing the fair value of the Series F Preferred Stock Warrants as of December 31, 2025. These estimates were derived using a Monte Carlo simulation model as of December 31, 2025, assuming a risk–free rate of 3.69%, an equity volatility rate of 85.0%, and an assumed future value $0.31 for one Series F Preferred Stock Warrant share. 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. Income Taxes We account for income taxes using the asset and liability method whereby deferred tax assets are recognized for deductible temporary differences, and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their respective tax basis. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. On this basis, as of December 31, 2025, we recorded a valuation allowance of $6.7 million against our net deferred tax liabilities. Off–Balance Sheet Arrangements We do not have any off–balance sheet arrangements. 54 Table of Contents Item 8. Financial Statements and Supplementary Data Table of Contents Page Report of Independent Registered Public Accounting Firm (PCAOB ID: 34) 56 Report of Independent Registered Public Accounting Firm (PCAOB ID: 298 ) 58 Consolidated Balance Sheets as of December 31, 2025 and 2024 59 Consolidated Statements of Operations for the Years Ended December 31, 2025 and 2024 60 Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2025 and 2024 61 Consolidated Statements of Cash Flows for the Years Ended December 31, 2025 and 2024 62 Notes to Consolidated Financial Statements 63 Note 1 – Organization, Description of Business, and Basis of Presentation 63 Note 2 – Summary of Significant Accounting Policies 64 Note 3 – Acquisitions 69 Note 4 – Discontinued Operations 72 Note 5 – Derivative Instruments 72 Note 6 – Fair Value Measurements 74 Note 7 – Property and Equipment, net 78 Note 8 – Asset Retirement Obligation 79 Note 9 – Accounts Payable and Accrued Expenses 79 Note 10 – Debt 79 Note 11 – Leases 82 Note 12 – Commitments and Contingencies 83 Note 13 – Mezzanine Equity 84 Note 14 – Stockholders’ Equity 85 Note 15 – Common Stock Options and Warrants 87 Note 16 – Long–Term Incentive Compensation 89 Note 17 – Earnings Per Share 91 Note 18 – Income Taxes 92 Note 19 – Related Party Transactions 93 Note 20 – Subsequent Events 95 Note 21 – Supplemental Oil and Gas Disclosures (Unaudited) 95 55 Table of Contents Report of Independent Registered Public Accounting Firm To the shareholders and the Board of Directors of Prairie Operating Co. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheet of Prairie Operating Co. and its subsidiaries (the “Company”) as of December 31, 2025, the related consolidated statements of operations, stockholders’ equity, and cash flows, for the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025, and the results of its operations and its cash flows for the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current–period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Proved Oil and Natural Gas Properties and Depletion — Oil and Natural Gas Reserves — Refer to Note 2 to the consolidated financial statements Critical Audit Matter Description The Company’s proved oil and gas properties are depleted using the units of production method based on estimated proved reserves. The development of the Company’s estimated proved reserve volumes requires management to make significant estimates and assumptions, including the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial reporting to the Securities and Exchange Commission. The Company engages an independent reserve engineer to estimate oil and natural gas quantities using these estimates and assumptions and engineering data. Changes in these assumptions could materially affect the estimated quantities of the Company’s reserves. Given the significant judgments made by management, performing audit procedures to evaluate the Company’s estimated proved reserve quantities, including management’s estimates and assumptions related to converting proved undeveloped reserves to producing properties within five years, required a high degree of auditor judgment and an increased extent of effort. 56 Table of Contents How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to management’s significant judgments and assumptions related to proved reserve quantities and converting proved undeveloped reserves to producing properties within five years included the following, among others: ● We compared the Company’s estimated future production to historical production volumes. ● We assessed the reasonableness of the production volume decline curves by comparing them to historical decline curve estimates. ● We compared the forecasts to actual conversions of proved undeveloped oil and gas reserves into proved developed oil and gas reserves. ● We evaluated the reasonableness of the forecasts by comparing the forecasts to the Company’s drill plan and the availability of capital relative to the drill plan. ● We assessed the reasonableness of the forecasts by comparing information in the forecasts to internal communications to management and the Board of Directors, forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies. ● We compared the Company’s proved reserve volumes to those independently developed by management’s expert, an independent reserve engineering firm. ● We evaluated the experience, qualifications and objectivity of management’s expert, an independent reserve engineering firm, including the methodologies used to estimate the proved reserve quantities. Accounting for the Series F Preferred Stock – Refer to Notes 6, 13, and 15 to the consolidated financial statements Critical Audit Matter Description On March 24, 2025, the Company entered into a securities purchase agreement with an investor (the “Series F Preferred Stockholder”), pursuant to which the Series F Preferred Stockholder agreed to purchase for an aggregate of $148.3 million (i) 148,250 shares of Series F Preferred Stock, with a stated value of $1,000 per share (the “Stated Value”), convertible into shares of Common Stock and (ii) upon the one–year anniversary of the issue date of the Series F Preferred Stock, subject to the satisfaction of certain conditions, warrants to purchase shares of Common Stock (the “Series F Preferred Stock Warrants”) (collectively, the “Series F Preferred Offering”). The Company’s determination of the appropriate accounting for the Series F Preferred Offering and the related valuation models and assumptions including the transaction discount rate, risk–free rates, equity volatility rates, and the assumed future value for one Series F Preferred Stock Warrant share involved significant complexity and judgment by management of the Company. We determined that our audit of the Company’s evaluation of the appropriate accounting and valuation models, and related assumptions, applied to the financial instruments included within the Series F Preferred Offering was a critical audit matter because it involved a high degree of auditor judgment, complexity, and required significant audit effort, including the need to involve professionals in our firm with expertise in accounting for complex financial instruments. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the accounting for the financial instruments included within the Series F Preferred Offering included the following, among others: ● With the assistance of professionals in our firm having expertise in accounting for complex financial instruments, we assessed the reasonableness of the Company’s conclusions as to the appropriate accounting for the financial instruments included within the Series F Preferred Offering in accordance with accounting principles generally accepted in the United States by: ● Evaluating the Company’s identification of relevant terms and conditions of the Series F Preferred Offering, including the identification of certain features of the Series F Preferred Stock that require bifurcation and separate accounting as embedded derivatives. ● Evaluating the Company’s application of available accounting guidance to the financial instruments included within the Series F Preferred Offering. ● With the assistance of professionals in our firm having expertise in the valuation of complex financial instruments, we assessed the reasonableness of the Company’s conclusions as to the valuation of the financial instruments included within the Series F Preferred Offering in accordance with accounting principles generally accepted in the United States by: ● Evaluating the Company’s identification of relevant terms and conditions of the Series F Preferred Offering. ● Evaluating the Company’s fair value models and related assumptions used in the valuations. ● Assessing the reasonableness of the significant inputs used in the valuations which required significant management judgment, including, among others; the transaction discount rate, risk–free rates, equity volatility rates, and the assumed future value for one Series F Preferred Stock Warrant share. ● With the involvement of our fair value specialists, we developed an independent fair value estimate and compared our estimate to the Company’s estimate and evaluated any differences. We developed our estimate by evaluating the inputs used by management or developing independent inputs. /s/ Deloitte & Touche LLP Houston, Texas March 30, 2026 We have served as the Company’s auditor since 2025. 57 Table of Contents Report of Independent Registered Public Accounting Firm To the Stockholders and the Board of Directors of Prairie Operating, Co. Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheet of Prairie Operating, Co. and its subsidiaries (the “Company”) as of December 31, 2024, the related consolidated statements of operations, stockholders’ equity/members’ deficit and cash flows for year ended December 31, 2024, and the related notes to the consolidated financial statements (collectively, the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024, and the results of its operations and its cash flows for the year ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. /s/ Ham, Langston, and Brezina, L.L.P. We have served as the Company’s auditor from 2023 to 2025. Houston, Texas March 6, 2025 58 Table of Contents Prairie Operating Co. and Subsidiaries Consolidated Balance Sheets (In thousands, except share amounts) December 31, 2025 December 31, 2024 Assets Current assets: Cash and cash equivalents $ 20 $ 5,192 Oil, natural gas, and NGL accrued revenue 22,728 3,024 Joint interest and other receivables 23,106 9,275 Derivative assets 28,812 — Inventory 3,604 5 Prepaid expenses and other current assets 1,452 312 Note receivable — 494 Total current assets 79,722 18,302 Property and equipment: Oil and natural gas properties, successful efforts method of accounting including $ 57,897 and $ 70,462 excluded from depletable base as of December 31, 2025 and 2024, respectively 852,732 134,953 Other property and equipment 21,067 94 Less: Accumulated depreciation, depletion, and amortization ( 49,343 ) ( 427 ) Total property and equipment, net 824,456 134,620 Derivative assets 24,627 — Debt issuance costs, net 12,642 1,731 Operating lease assets 2,966 1,323 Other non–current assets 133 578 Total assets $ 944,546 $ 156,554 Liabilities, Mezzanine Equity, and Stockholders’ Equity Current liabilities: Accounts payable and accrued expenses $ 62,792 $ 38,225 Oil, natural gas, and NGL revenue payable 30,300 2,366 Ad valorem and production taxes payable 31,385 7,094 Senior convertible note, at fair value — 12,555 Derivative liabilities — 2,446 Operating lease liabilities 1,300 323 Total current liabilities 125,777 63,009 Long–term liabilities: Credit facility 366,000 28,000 Subordinated note – related party 1,458 4,609 Subordinated note warrants, at fair value – related party 316 4,159 Series F convertible preferred stock embedded derivatives, at fair value 15,853 — Series F convertible preferred stock warrants, at fair value 90,134 — SEPA, at fair value — 790 Derivative liabilities — 1,949 Oil, natural gas, and NGL revenue payable 27,402 — Ad valorem and production taxes payable 22,751 — Deferred tax liability 21,652 — Asset retirement obligation 4,019 227 Operating lease liabilities 1,792 1,043 Other long–term liabilities 1,082 — Total long–term liabilities 552,459 40,777 Total liabilities 678,236 103,786 Commitments and contingencies (Note 12) Mezzanine equity: Series F convertible preferred stock; $ 0.01 par value; 50,000,000 shares authorized, and 121,050 and 0 shares issued and outstanding as of December 31, 2025 and 2024, respectively 136,146 — Stockholders’ equity: Series D convertible preferred stock; $ 0.01 par value; 50,000 shares authorized, and 5,982 and 14,457 shares issued and outstanding as of December 31, 2025 and 2024, respectively — — Common stock; $ 0.01 par value; 500,000,000 shares authorized, and 62,499,375 and 23,045,209 shares issued and outstanding as of December 31, 2025 and 2024, respectively 625 230 Treasury stock, at cost; 111,357 and 0 shares issued and outstanding as of December 31, 2025 and 2024, respectively ( 531 ) — Additional paid–in capital 217,785 172,304 Accumulated deficit ( 87,715 ) ( 119,766 ) Total stockholders’ equity 130,164 52,768 Total liabilities, mezzanine equity, and stockholders’ equity $ 944,546 $ 156,554 The accompanying notes are an integral part of these consolidated financial statements. 59 Table of Contents Prairie Operating Co. and Subsidiaries Consolidated Statements of Operations (In thousands, except share and per share amounts) Years Ended December 31, 2025 2024 Revenues: Crude oil sales $ 204,040 $ 6,595 Natural gas sales 9,472 551 NGL sales 28,136 793 Total revenues 241,648 7,939 Operating expenses: Lease operating expenses 41,411 1,265 Transportation and processing expenses 8,910 864 Ad valorem and production taxes 21,231 591 Depreciation, depletion, and amortization 48,916 427 Accretion of asset retirement obligation 247 6 Exploration expenses 1,332 734 Abandonment and impairment of unproved properties 3,409 — General and administrative expenses 50,614 30,565 Total operating expenses 176,070 34,452 Income (loss) from operations 65,578 ( 26,513 ) Other (expenses) income: Interest expense ( 28,521 ) ( 1,142 ) Gain (loss) on derivatives, net 79,230 ( 4,395 ) Loss on adjustment to fair value – embedded derivatives, debt, and warrants ( 63,341 ) ( 5,358 ) Loss on issuance of debt — ( 3,039 ) Interest income and other 759 580 Total other expenses ( 11,873 ) ( 13,354 ) Income (loss) from operations before income taxes 53,705 ( 39,867 ) Income tax expense ( 21,654 ) — Net income (loss) from continuing operations 32,051 ( 39,867 ) Discontinued operations Loss from discontinued operations, net of taxes — ( 1,045 ) Net loss from discontinued operations — ( 1,045 ) Net income (loss) attributable to Prairie Operating Co. 32,051 ( 40,912 ) Series F preferred stock declared dividends ( 11,269 ) — Series F preferred stock undeclared dividends ( 1,211 ) — Remeasurement of Series F preferred stock ( 80,478 ) — Net loss attributable to Prairie Operating Co. common stockholders $ ( 60,907 ) $ ( 40,912 ) Loss per common share: Loss per share, basic and diluted $ ( 1.35 ) $ ( 2.65 ) Weighted average common shares outstanding, basic and diluted 45,232,756 15,453,502 The accompanying notes are an integral part of these consolidated financial statements. 60 Table of Contents Prairie Operating Co. and Subsidiaries Consolidated Statement of Stockholders’ Equity (In thousands, except share amounts) Series D Preferred Stock Par value $ 0.01 Series E Preferred Stock Par value $ 0.01 Common Stock Par value $ 0.01 Treasury Stock Additional Paid In Accumulated Stockholders’ Shares Amount Shares Amount Shares Amount Share Amount Capital Deficit Equity January 1, 2024 balance 20,627 — 20,000 — 9,826,719 98 — — 118,928 ( 78,854 ) 40,172 Conversion of Series D Preferred Stock ( 6,170 ) — — — 1,234,090 12 — — ( 12 ) — — Conversion of Series E Preferred Stock — — ( 20,000 ) — 4,000,000 40 — — ( 40 ) — — Issuance of Common Stock upon warrant exercise — — — — 5,589,740 57 — — 33,482 — 33,539 Issuance of Common Stock to fund NRO Acquisition, net of issuance costs — — — — 1,827,040 18 — — 9,974 — 9,992 Issuance of Common Stock for SEPA commitment fee — — — — 100,000 1 — — 599 — 600 Issuance of Common Stock as part of credit facility issuance costs — — — — 120,048 1 — — 999 — 1,000 Issuance of Common Stock related to stock based compensation — — — 347,572 3 — — ( 3 ) — — Stock based compensation — — — — — — — — 8,377 — 8,377 Net loss — — — — — — — — — ( 40,912 ) ( 40,912 ) December 31, 2024 balance 14,457 $ — — $ — 23,045,209 $ 230 — $ — $ 172,304 $ ( 119,766 ) $ 52,768 Conversion of Series D Preferred Stock ( 8,475 ) — — — 1,695,000 17 — — ( 17 ) — — Conversion of Series F Preferred Stock — — — — 13,024,200 131 — — 38,359 — 38,490 Issuance of Common Stock for Series F Preferred Stock dividends — — — — 5,532,000 55 — — 10,768 — 10,823 Issuance of Common Stock upon option exercise — — — — 2,993,842 30 — — 603 — 633 Issuance of common stock upon Senior Convertible Note conversion — — — — 2,118,862 21 — — 18,143 — 18,164 Issuance of common stock to fund Bayswater Acquisition, net of issuance costs — — — — 9,736,904 97 — — 39,863 — 39,960 Issuance of common stock to seller as part of Bayswater Acquisition — — — — 3,656,099 37 — — 15,963 — 16,000 Issuance of Common Stock related to stock based compensation — — — — 808,616 7 — — ( 7 ) — — Purchase of treasury stock — — — — ( 111,357 ) — 111,357 ( 531 ) — ( 531 ) Stock based compensation — — — — — — — — 14,764 — 14,764 Series F Preferred Stock declared dividends — — — — — — — — ( 11,269 ) — ( 11,269 ) Series F Preferred Stock undeclared dividends — — — — — — — — ( 1,211 ) — ( 1,211 ) Remeasurement of Series F Preferred Stock — — — — — — — — ( 80,478 ) — ( 80,478 ) Net income — — — — — — — — — 32,051 32,051 December 31, 2025 balance 5,982 $ — — $ — 62,499,375 $ 625 111,357 $ ( 531 ) $ 217,785 $ ( 87,715 ) $ 130,164 The accompanying notes are an integral part of these consolidated financial statements. 61 Table of Contents Prairie Operating Co. and Subsidiaries Consolidated Statements of Cash Flows (In thousands) Year Ended December 31, 2025 2024 Cash flows from operating activities: Net income (loss) from continuing operations $ 32,051 $ ( 39,867 ) Adjustment to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation, depletion, and amortization 48,916 427 Accretion of asset retirement obligation 247 6 Abandonment and impairment of unproved properties 3,409 — Stock based compensation 14,764 8,377 Unrealized (gain) loss on derivatives ( 57,834 ) 4,395 Loss on adjustment to fair value – embedded derivatives, debt, and warrants 63,341 5,358 Deferred income tax expense 21,654 — Amortization of deferred financing costs 3,175 35 Loss on issuance of debt — 3,039 Non–cash SEPA commitment fee — 600 Changes in operating assets and liabilities: Oil, natural gas, and NGL accrued revenue ( 19,703 ) ( 3,024 ) Joint interest and other receivables ( 6,229 ) ( 9,241 ) Inventory ( 3,552 ) — Prepaid expenses and other current assets ( 1,140 ) ( 74 ) Accounts payable and accrued expenses 19,202 18,590 Oil, natural gas, and NGL revenue payable 17,478 1,140 Ad valorem and production taxes payable 17,947 496 Other assets and liabilities 176 ( 65 ) Net cash provided by (used in) continuing operating activities 153,902 ( 9,808 ) Net cash provided by discontinued operations — 460 Net cash provided by (used in) operating activities 153,902 ( 9,348 ) Cash flows from investing activities: Cash paid for Bayswater asset purchase, net of cash received ( 459,593 ) — Development of oil and natural gas properties ( 177,700 ) ( 28,522 ) Other asset and leasehold purchases ( 19,428 ) ( 94 ) Cash received from payment on note receivable related to sale of cryptocurrency miners 805 338 Cash paid for Nickel Road asset purchase, net of cash received — ( 55,509 ) Transaction expenses paid related to Nickel Road asset purchase — ( 239 ) Deposit on other oil and natural gas properties purchase — ( 382 ) Cash received from sale of cryptocurrency miners — 1,000 Net cash used in investing activities ( 655,916 ) ( 83,408 ) Cash flows from financing activities: Borrowings on the Credit Facility 390,000 28,000 Repayment on the Credit Facility ( 52,000 ) — Debt issuance costs associated with the Credit Facility ( 14,085 ) ( 336 ) Proceeds from the issuance of Common Stock 43,817 15,000 Financing costs associated with issuance of Common Stock ( 3,857 ) ( 5,008 ) Proceeds from the issuance of Series F Preferred Stock 148,250 — Financing costs associated with the issuance of Series F Preferred Stock ( 12,171 ) — Proceeds from the issuance of the Subordinated Note – related party — 5,000 Payments of the Subordinated Note – related party ( 3,214 ) ( 1,786 ) Proceeds from the issuance of the Senior Convertible Note — 14,250 Payments of the Senior Convertible Note — ( 3,748 ) Proceeds from option exercise 633 — Treasury stock repurchased ( 531 ) — Proceeds from the exercise of Series D and E Preferred Stock warrants — 33,539 Net cash provided by financing activities 496,842 84,911 Net decrease in cash and cash equivalents ( 5,172 ) ( 7,845 ) Cash and cash equivalents, beginning of the year 5,192 13,037 Cash and cash equivalents, end of the year $ 20 $ 5,192 The accompanying notes are an integral part of these consolidated financial statements. Refer to Note 2 – Summary of Significant Accounting Policies for supplemental cash flow disclosures. 62 Table of Contents Prairie Operating Co. and Subsidiaries Notes to Consolidated Financial Statements Note 1 – Organization, Description of Business, and Basis of Presentation Organization and Description of Business Prairie Operating Co. (individually or together with its subsidiaries, the “Company”) is an independent oil and gas company focused on the acquisition and development of crude oil, natural gas, and natural gas liquids (“NGLs”). The Company’s assets and operations are strategically located in the oil region of rural Weld County, Colorado, within the Denver–Julesburg Basin (the “DJ Basin”). As of December 31, 2025, the Company’s assets included approximately 68,000 net leasehold acres in, on and under approximately 98,200 gross acres. In addition to growing production through its drilling operations, the Company intends to continue growing its business through accretive acquisitions, such as the NRO Acquisition (as defined herein), which closed in October 2024, the Bayswater Acquisition (as defined herein), which closed in March 2025, the Edge Acquisition (as defined herein), 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. Refer to Note 3 – Acquisitions for a discussion of the Company’s acquisitions. Basis of Presentation and Consolidation The accompanying consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations, and cash flows for the years presented in accordance with GAAP and the accounts of the Company and its wholly–owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The Company owns 100 % of Prairie Operating Co., LLC, a Delaware limited liability company (“Prairie LLC”), which is considered a variable interest entity for which the Company is the primary beneficiary, as the Company is the sole managing member of Prairie LLC and has the power to direct the activities most significant to Prairie LLC’s economic performance, as well as the obligation to absorb losses and receive benefits that are potentially significant. 63 Table of Contents Segment Information The Company operates in one business segment: the acquisition, development, and production of crude oil, natural gas, and NGLs (the “Reportable Segment”), primarily in the DJ Basin. This is consistent with the internal reporting provided to the Company’s executive team, made up of the Interim President and Chief Executive Officer and the Executive Vice President – Chief Financial Officer, who are considered the chief operating decision makers (“CODM”). The Company’s Reportable Segment produces and sells crude oil, natural gas, and NGL volumes, which is reported as oil, natural gas, and NGL revenue on its consolidated statements of operations for the years ended December 31, 2025 and 2024. The Company’s revenue recognition policy and other accounting policies for its Reportable Segment are the same as its company–wide accounting policies discussed below in Note 2 – Summary of Significant Accounting Policies . The Reportable Segment’s major customers during the years ended December 31, 2025 and 2024 are also discussed below in Note 2 – Summary of Significant Accounting Policies. Additionally, the Company did not have any intra–entity sales or transfers during the years ended December 31, 2025 or 2024, and the Reportable Segment’s significant expenses are the same as those reported on the consolidated statements of operations for the years ended December 31, 2025 and 2024. Additionally, the CODM does not receive additional information regarding expenses other than what is reported on the consolidated statements of operations for the years ended December 31, 2025 and 2024. The CODM assesses the performance of the Reportable Segment and decides how to allocate resources based on the Company’s net income (loss), as reported on the consolidated statements of operations. Additionally, net income (loss) on the consolidated statements of operations is used to monitor budget versus actual results of the Reportable Segment and to benchmark against the Company’s competitors. The CODM’s measure of the Reportable Segment assets are reported as total assets on the consolidated balance sheets. Note 2 – Summary of Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from these estimates. These estimates and assumptions include estimates for reserve quantities and estimated future cash flows associated with proved reserves, depletion of proved developed oil and natural gas reserves, asset retirement obligations, accruals for the Company’s oil, natural gas, and NGL revenues and any potential liabilities, the valuation of the Series F Convertible Preferred Stock, $ 0.01 par value per share (“Series F Preferred Stock”), Series F Preferred Stock Warrants (as defined herein), and the Company’s stock–based compensation performance based awards, the fair value of commodity derivative instruments, the realization of deferred tax assets, and any acquisition–related purchase price allocations. Cash and Cash Equivalents Cash and cash equivalents are defined by the Company as short–term, highly liquid investments which have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. The carrying value of cash and cash equivalents approximate the fair value due to the short–term nature of these instruments. The Company may have cash balances which exceed the federal deposit insurance limits of $ 250,000 , creating a potential credit risk. To mitigate this risk, the Company maintains its cash and cash equivalents with high quality financial institutions; therefore, it does not anticipate incurring any losses related to these credit risks. As of December 31, 2025 and 2024, the Company had cash and cash equivalents of less than $ 0.1 million and $ 5.2 million, respectively. Joint Interest and Other Receivables Joint interest and other receivables consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date and, at times, receivables from the counterparties to the Company’s derivative contracts. In the Company’s capacity as operator, it incurs development, exploration, operating, and plug and abandonment costs which are billed to its partners based on their respective working interests. For receivables from joint interest owners, the Company typically has the ability to withhold revenue distributions to recover any unpaid joint operations billings which are past due. 64 Table of Contents Oil and Natural Gas Properties Proved properties. The Company follows the successful efforts method of accounting for its 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. The Company assesses its proved oil and natural gas properties for impairment whenever circumstances indicate that the carrying value of proved oil and natural gas properties may not be recoverable. In this assessment, the Company compares unamortized capitalized costs to the expected undiscounted pre–tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre–tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Topic (“ASC”) 820, Fair Value Measurements (“ASC 820”). If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market–based weighted average cost of capital. Unproved properties . Under the successful efforts method of accounting for oil and natural gas properties, unproved properties, such as the costs to acquire undeveloped leases, are not subject to depletion until they are transferred to proved properties. The Company transfers leasehold costs to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Additionally, 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. The following table presents the property balances excluded from the Company’s UOP depletion calculation for the years indicated: December 31, 2025 December 31, 2024 (In thousands) Acquisition costs $ 32,796 $ 29,335 Development costs (1) 25,101 41,127 Total excluded from depletable base $ 57,897 $ 70,462 (1) As of December 31, 2025, the majority of the development costs relate to wells which were in the process of being completed. These wells are scheduled to come online throughout the first and second quarters of 2026 and will be reflected in proved properties and the Company’s UOP depletion calculation at that time. The Company evaluates its unproved properties for impairment on a yearly basis by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by us or other market participants. If circumstances dictate that the carrying value of unproved properties may not be recoverable, the Company performs a recoverability test. If carrying values exceed the undiscounted future net cash flows associated with the unproved reserves, impairment is measured and recorded at fair value, which is generally estimated using the income approach described in ASC 820. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market–based weighted average cost of capital. Additionally, the Company expenses any costs related to the expiration of unproved leasehold. During the year ended December 31, 2025, the Company recorded $ 3.4 million related to leases which expired, which is presented as abandonment and impairment of unproved properties expense on its consolidated statement of operations. The Company did no t record any abandonment and impairment of unproved properties expense the year ended December 31, 2024. Exploratory costs . Exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. Under the successful efforts method of accounting, exploratory drilling costs are initially capitalized pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. If proved reserves are not found, the costs related to unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If the Company determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. To date, the Company has not drilled any exploratory wells but may have exploratory drilling in future years. 65 Table of Contents Other Property and Equipment As part of the Bayswater Acquisition, the Company acquired several salt–water disposal wells and the associated facilities, equipment, and pipelines (collectively, the “SWD Facilities”). The Company has accounted for the SWD Facilities at its relative fair value allocated to the assets as of March 26, 2025, the closing date of the Bayswater Acquisition, adjusted for the interim settlement statement and final settlement statement, as discussed further below. The Company is depreciating the SWD Facilities using the straight–line method over an estimated 30 –year life from May 2023 and 2024, the dates the SWD facilities were constructed. Refer to Note 3 – Acquisitions for a discussion of the Bayswater Acquisition. Additionally, other property and equipment also includes of vehicles, computer equipment, and office furniture and fixtures which are depreciated using the straight–line method over their estimated useful lives of five years . Derivative Instruments The Company utilizes commodity derivative instruments to reduce its exposure to crude oil and natural gas price volatility for a portion of its estimated production from its proved, developed, producing oil and natural gas properties. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third–party industry–standard pricing model. Refer to Note 6 – Fair Value Measurements for a further discussion of the fair value of the Company’s derivative instruments. The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds or payments related to the early termination of derivative contracts during the period are recognized as net gain or loss on derivatives, as applicable, in the consolidated statements of operations. Refer to Note 4 – Derivative Instruments for a discussion of the Company’s outstanding derivative instruments. Prepaid Expenses and Other Current Assets The Company’s prepaid expenses and other current assets primarily consists of premiums paid for its various insurance packages, including commercial packages, general liability, and Director and Officer policies, and performance bonds which are amortized into general and administrative expenses over the life of the policy and prepaid software licenses and subscriptions which are amortized into general and administrative or lease operating expenses, depending on the type of license or subscription, over the term of the license or subscription. Debt Issuance Costs Debt issuance costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Company’s amended and restated reserve–based credit agreement (the “Credit Facility”) with Citibank, N.A. (“Citi”) are capitalized as debt issuance costs, net on the accompanying balance sheets and amortized to interest expense on the accompanying statements of operations on a straight–line basis over the life of the Credit Facility. Refer to Note 10 – Debt for a discussion of the Company’s Credit Facility. Leases The Company capitalizes its operating leases as right–of–use (“ROU”) assets and lease liabilities on the accompanying consolidated balance sheets and recognizes the fixed minimum lease costs for its operating leases on a straight–line basis over the lease term in accordance with ASC Topic 842, Leases (“ASC 842”). The Company does not recognize leases with initial lease terms less than or equal to 12 months on the balance sheet and only includes those short–term leases as part of its lease–related disclosures. Additionally, the Company does not include any of its variable lease costs in the calculation of its ROU assets and lease liabilities, instead variable costs are expensed as incurred. The Company makes certain assumptions and judgments when determining its ROU assets and lease liabilities. When determining whether a contract contains a lease, the Company considers whether there is an identified asset that is physically distinct, whether the supplier has substantive substitution rights, whether the Company has the right to obtain substantially all of the economic benefits from the use of the asset, and whether it has the right to control the asset. Certain of the Company’s leases include one or more options to renew the lease, with renewal terms that can extend the lease term for additional years. When determining if renewals should be included in the lease term to be recognized, the Company utilizes the reasonably certain threshold, therefore, certain of the leases included in the calculation of its ROU assets and lease liabilities could include optional renewal periods for which it is not contractually obligated. Additionally, the Company must estimate its incremental borrowing rate when the implicit rate is not stated in the lease agreement and cannot be readily determined. As of December 31, 2025, none of the Company’s active leases contain purchase or termination options that are reasonably certain to be exercised. The Company has certain operating leases for office space, vehicles, and equipment used in its daily operations, for which it records the related lease costs as general and administrative or lease operating expenses, depending on the type of lease, on the accompanying consolidated statements of operations. Refer to Note 11 – Leases for further information related to the Company’s operating leases. Asset Retirement Obligations The Company’s oil and natural gas properties include estimates of future expenditures to plug and abandon wells, pipelines, platforms, and other related facilities after the reserves have been depleted. The Company recognizes the present value of the asset retirement obligation costs as a liability when it is incurred or assumed (acquired) and an increase to its capitalized oil and natural gas properties. The capitalized asset retirement obligation costs are depleted over the productive lives of the oil and natural gas properties while the asset retirement obligation liability is accreted to the expected settlement value over the productive lives of the oil and natural gas properties. Upon settlement, the difference between the recorded liability amount and the amount of costs incurred will be recognized as an adjustment to the capitalized cost of oil and natural gas properties. 66 Table of Contents The determination of future asset retirement obligations requires estimates of the future costs of removal and restoration, productive lives of the oil and natural gas properties based on reserve estimates, and future inflation rates. Estimated costs consider historical experience, third–party estimates, and government regulatory requirements but do not consider salvage values. These costs could be subject to revisions in subsequent years due to changes in regulatory requirements, the estimated plug and abandonment cost, and the estimated timing of the oil and natural gas property retirement. In subsequent periods, if the estimate of the asset retirement obligation liability changes, the Company records an adjustment to both the asset retirement obligation liability and the oil and natural gas property carrying value. Additionally, the Company estimates the credit–risk adjusted discount rate, which is applied to the future inflated plug and abandonment costs to determine the discounted present value which is recognized as the initial liability. The determined credit–risk adjusted discount rate is also subsequently applied to accrete the liability. Refer to Note 8 – Asset Retirement Obligations for further information related to the Company’s asset retirement obligations. Commitments and Contingencies The Company recognizes a liability for loss contingencies when it is probable a liability has been incurred, and the amount can be reasonably estimated. If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range, the Company accrues that amount. When no amount within the range is a better estimate than any other amount the Company accrues the minimum amount in the range. Additionally, the Company could be subject to legal actions and claims arising in the ordinary course of business, which, if considered probable and reasonably estimable, would require a contingent liability to be recorded as general and administrative expense. Additionally, following the close of the Bayswater Acquisition in March 2025, the Company is party to an oil transportation agreement which includes a minimum volume commitment, requiring the Company to transport a fixed determinable quantity of crude oil on a monthly basis. Under the terms of this agreement, the Company may be required to make periodic deficiency payments for any shortfalls in delivering the minimum gross volume to be transported by the counterparty. Additionally, one of the Company’s gas gathering contracts requires a monthly guaranteed payment intended to reimburse the counterparty for costs incurred to connect to the gathering facility. Refer to Note 12 – Commitments and Contingencies for further information related to the Company’s commitment contracts. Liabilities at Fair Value The Company has several financial instruments which were evaluated for embedded derivatives and bifurcation in accordance with ASC Topic 815, Derivatives and Hedging (“ASC 815”) at the time of issuance. Pursuant to ASC 815, the Company has determined that the Standby Equity Purchase Agreement (the “SEPA”), convertible promissory note (the “Senior Convertible Note”), the subordinated promissory note (the “Subordinated Note”) Warrants, Series F Preferred Stock Warrants (as defined herein), and certain features of the Series F Preferred Stock should be accounted for at fair value. As a result, the Company has reflected these financial instrument liabilities at their fair value on its consolidated balance sheet and reflects the changes in the fair values of the liabilities as loss on adjustment to fair value – embedded derivatives, debt, and warrants on its consolidated statements of operations. The Company has engaged a third–party valuation expert to assist in preparing the fair value valuations of these financial instruments at each reporting period. Refer to Note 6 – Fair Value Measurements for a full discussion of the fair values of the SEPA, the Senior Convertible Note, the Subordinated Note Warrants, Series F Preferred Stock, and Series F Preferred Stock Warrants. Revenue Recognition The following table presents the Company’s oil, natural gas, and NGL revenues disaggregated by revenue stream: Year Ended December 31, 2025 (1) 2024 (In thousands) Crude oil sales $ 204,040 $ 6,595 Natural gas sales 9,472 551 NGL sales 28,136 793 Total revenues $ 241,648 $ 7,939 (1) Total revenues for the year ended December 31, 2025, include revenue from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. The Company recognizes revenue from the sales of crude oil, natural gas, and NGLs at the point that control of the produced oil, natural gas, and NGL volumes are transferred to the purchaser, which may differ depending on the applicable contractual terms. The Company considers the transfer of control to have occurred when the production is delivered to the purchaser because at that time, the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the oil, natural gas, or NGL production. Transfer of control dictates the presentation of the Company’s transportation and processing expenses within its consolidated statements of operations. Transportation and processing expenses incurred prior to the transfer of control are recorded gross within transportation and processing expenses in the accompanying consolidated statements of operations. Gathering, transportation, and processing expenses incurred subsequent to the transfer of control are recorded net within crude oil, natural gas, and NGL sales revenues. Oil revenue contracts. The majority of the Company’s oil revenue contracts are structured so that the Company delivers production at the wellhead or other contractually agreed–upon delivery point, at which time the purchaser takes custody, title, and risk of loss of the product, and the Company receives a specified index price from the purchaser with no deduction. As such, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser and records the third–party transportation costs as a component of transportation and processing expenses in the accompanying consolidated statements of operations. 67 Table of Contents Natural gas and NGLs revenue contracts . Under the Company’s natural gas processing contracts, the Company delivers natural gas to a processing entity at the wellhead or the inlet of the processing entity’s system. Typically, the Company relinquishes control at the inlet of the midstream processing facility and recognizes natural gas and NGL revenues based on the agreed upon contracted amount of proceeds received from the midstream processor. As such, the Company recognizes the revenue associated with these contracts net of gathering and processing costs. Additionally, the Company has made an accounting election to exclude certain qualifying taxes collected from customers and remitted to governmental authorities from its reported revenues and is presenting those amounts as a component of operating expense in the accompanying consolidated statements of operations. The amounts due from purchasers are reflected in oil, natural gas, and NGL accrued revenue on the accompanying consolidated balance sheets and consists of uncollateralized accrued oil, natural gas, and NGL revenue due under normal trade terms, generally requiring payment within 30 days of production. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Additionally, the Company has determined that product returns or refunds are very rare and will account for them as they occur, and it generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specification. As discussed above, the Company 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, the Company 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 the Company’s largest customers accounted for approximately 83 % and 10 % of its oil, natural gas, and NGL revenues. The Company is exposed to credit risk in the event of nonpayment by the purchasers of its production, all of which are concentrated in energy–related industries and may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. While the loss of a single purchaser may result in a temporary interruption in sales of, or a lower price for, the Company’s production, the Company does not believe the loss of any single purchaser would have a material