Prairie Operating Co. 10-K

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, 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.”). 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 82% of Colorado’s oil production as of December 2024. 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, 2024, our exploration and production (“E&P”) assets consist of our Central Weld Assets (as defined herein), Genesis and Genesis Bolt–on Assets (as defined herein), and the Exok Option Purchase (as defined herein) assets. Our Central Weld Assets were acquired from Nickel Road Development LLC and Nickel Road Operating LLC (collectively, “NRO”) in October 2024 and include 26 revenue producing oil and natural gas wells. As of December 31, 2024, our total Genesis Assets include approximately 18,100 net leasehold acres in, on and under approximately 31,000 gross acres and our Central Weld Assets include approximately 5,640 net leasehold acres, on and under approximately 6,000 gross acres. We commenced drilling wells on our Genesis Bolt-on Assets in the third quarter of 2024 and all eight wells began producing in February 2025. Previously, we focused on cryptocurrency mining until the sale of our cryptocurrency miners in January 2024. Our cryptocurrency mining operations commenced on May 3, 2023 concurrent with the Merger (as defined herein). Prior to January 2024, all of our revenue was generated through our cryptocurrency mining activities from assets that were acquired in the Merger. Upon the closing of the Crypto Sale (as defined herein), we exited the cryptocurrency mining business. Refer to Recent Developments below for more information. On May 3, 2023, we completed our merger with Prairie Operating Co., LLC, a Delaware limited liability company (“Prairie LLC”), pursuant to the terms of the Amended and Restated Agreement and Plan of Merger, dated as of May 3, 2023 (the “Merger Agreement”), by and among the Company, Creek Road Merger Sub, LLC (“Merger Sub”), and Prairie LLC, pursuant to which, among other things, Merger Sub merged with and into Prairie LLC, with Prairie LLC surviving and continuing to exist as a Delaware limited liability company and a wholly-owned subsidiary of the Company (the “Merger”). Upon the Merger, membership interests in Prairie LLC were converted into the right to receive each member’s pro rata share of 2,297,668 shares of common stock, par value $0.01 per share, of the Company (“Common Stock”). Upon consummation of the Merger, we changed our name from “Creek Road Miners, Inc.” to “Prairie Operating Co.” We traded under our former name and ticker symbol “CRKR” until October 16, 2023. From October 16, 2023 to November 12, 2023, we traded under symbol “CRKRD,” a transitionary ticker symbol. We began trading under our current ticker symbol, “PROP,” on November 13, 2023. On December 21, 2023, we received approval to list our common stock on the Nasdaq Capital Market (“Nasdaq”). Trading of our shares of common stock on Nasdaq under the ticker symbol “PROP” commenced at the opening of trading on December 28, 2023. On October 16, 2023, we effected a reverse stock split at an exchange ratio of 1:28.5714286. Unless otherwise noted, all per share and share amounts presented herein have been retroactively adjusted for the effect of the reverse stock split for all periods presented. 3 Recent Developments Bayswater Acquisition On February 6, 2025, we and certain of our subsidiaries entered into a Purchase and Sale Agreement (the “Bayswater PSA”) with 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”), pursuant to which we agreed to acquire the Bayswater Assets from Bayswater for a purchase price of $602.8 million, subject to certain closing price adjustments (all together, the “Bayswater Acquisition”). The Bayswater Acquisition has an outside closing date of March 15, 2025, subject to customary closing conditions, with an economic effective date of December 1, 2024. However, there can be no assurance that a closing will occur. The Bayswater PSA contains customary representations, warranties and covenants of us and Bayswater for a transaction of this nature. NRO Acquisition On January 11, 2024, we entered into an asset purchase agreement (the “NRO Agreement”), by and among the Company, Prairie LLC and NRO, to acquire the assets of NRO (the “Central Weld Assets”) for total consideration of $94.5 million (the “Purchase Price”), subject to certain closing price adjustments and other customary closing conditions (the “NRO Acquisition”). The Purchase Price consists of $83.0 million in cash and $11.5 million in deferred cash payments. The Company deposited $9 million of the Purchase Price into an escrow account on January 11, 2024 (the “Deposit”). On August 15, 2024, we and NRO agreed to amend certain terms of the NRO Agreement, pursuant to which the total consideration of the NRO Acquisition was reduced to $84.5 million in cash, subject to certain closing price adjustments and other customary closing conditions, and the parties agreed to remove the deferred cash payments. Additionally on August 15, 2024, $6.0 million of the Deposit was released to NRO and the remaining $3.0 million was returned to us. On October 1, 2024, we closed the NRO Acquisition and paid $49.6 million to the sellers in cash, using cash on hand, the proceeds from the issuance of Common Stock, and a portion of the proceeds from the issuance of the Senior Convertible Note (as defined herein). We completed the final settlement with NRO in December 2024, which resulted in a final purchase price of $55.5 million. Sale of Crypto Assets On January 23, 2024, pursuant to an asset purchase agreement (the “Crypto Divestiture Agreement”) between us and a private purchaser (the “Crypto Purchaser”), we sold all of our cryptocurrency miners (the “Mining Equipment”) 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 Crypto Purchaser associated with or otherwise attributable to the Mining Equipment until the aggregate amount of such payments equals $250,000 and (b) thereafter, 50% of the monthly net revenues received by the Crypto Purchaser associated with or otherwise attributable to the Mining Equipment until the aggregate amount of such payments equals the Deferred Purchase Price, plus accrued interest (the “Crypto Sale”). The Crypto Sale closed on January 23, 2024, simultaneously with the execution of the Crypto Divestiture Agreement. In addition to the sale of the Mining Equipment, we assigned, and the Crypto Purchaser assumed, all of our rights and obligations under the Master Services Agreement, dated February 16, 2023, by and between Atlas Power Hosting, LLC (“Atlas”) and us (the “Atlas MSA”), pursuant to which Atlas hosts, operates, and manages the Mining Equipment. Pursuant to the Atlas MSA, the Crypto Purchaser will receive payment in U.S. dollars for the daily net mining revenue representing the dollar value of the cryptocurrency award generated less power and other costs. Genesis Bolt-on Acquisition On February 5, 2024, we acquired 1,280 gross leasehold acres on a drillable spacing unit and eight PUD drilling locations in the DJ Basin (the “Genesis Bolt-on Assets”) from a private seller for $0.9 million. 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 favorable 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. 4 Maximize returns and capital efficiency. We will utilize the latest technology in 3-D seismic mapping and geo-steering to decrease drill times and improve well results. Additionally, we will use our management’s extensive experience 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. Our Operations Genesis Assets Upon the closing of the Merger, 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 certain undeveloped oil and natural gas leases 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 and purchased additional oil and natural gas leases from Exok, consisting of approximately 25,240 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 the Genesis Bolt–on Assets from a private seller for $0.9 million. These assets offset the other oil and natural gas assets held by us in northern Weld County, Colorado. We refer to the Initial Genesis Assets and the Genesis Bolt-on Assets, collectively, as the “Genesis Assets.” As of December 31, 2024, the total Genesis Assets include approximately 18,100 net leasehold acres in, on and under approximately 31,000 gross acres. In August 2024, we began drilling eight wells on the Genesis Assets acreage which cover approximately 915 net leasehold acres in, on and under approximately 1,115 gross acres. These wells began producing in February 2025. Approximately 87% of the net leasehold of our Initial Genesis Assets are leased from private landowners, with the remaining 13% under State of Colorado leases. The Initial Genesis Assets fee leases are burdened with total royalties of 25% and the State of Colorado leases are burdened with total royalties of 22.5%. All of our Genesis Bolt-on Assets are leased from private landowners and are burdened with average royalties of 20%. Further, none of the Genesis Assets leases are subject to federal leases. All of the Genesis Assets acreage is held by crude oil and natural gas leases with varying expiration dates, some with options to extend ranging from 1 to 4 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. The Genesis Assets are located in and around wells drilled in both the Niobrara Shale and the Codell Sandstone formations within the DJ Basin. While production activities in the DJ Basin date back to the 1970s, production within the DJ Basin has increased rapidly since the horizontal drilling boom in 2009, with both the Niobrara and Codell formations contributing to this activity. Within our DJ Basin operating area, there are over 1,300 legacy vertical wells, and the primary drilling objective in this area is crude oil production from the fractured Codell and Niobrara formations. The area has seen a renewed interest in drilling activity over the past decade in conjunction with drilling success in the Niobrara in the DJ Basin on the front range of Colorado. Active operators in the area include Chevron Corporation, Civitas Resources, Inc., Verdad Resources LLC, Bison Oil and Gas, EOG Resources, Inc., Samson Energy Company, LLC, and others. There is ample takeaway infrastructure in place within several miles of the Genesis Assets, including multiple midstream operators such as Summit Midstream Partners LP, Taproot Energy Partners LLC, Rimrock Energy Partners LLC, and NGL Energy Partners LP. 5 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, which all began producing in February 2025. In order to continue the development plan of our Genesis Assets, we plan to drill up to 6 gross wells in 2025 and up to 12 gross wells in 2026. 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. Prior to the Shelduck wells, we had no operating history of drilling successfully producing oil and natural gas wells. 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. We have historically incurred significant losses and experienced negative cash flow and have not generated any revenue related to the exploration and production of oil and natural gas assets to date. Ensuring that permits are received in a timely manner is critical to our development plan. With respect to our Initial Genesis Assets, on November 27, 2023 we announced that we had submitted a Weld County Oil and Gas Location Assessment (“WOGLA”) application for sites within the Genesis OGDP (“Genesis 1”) and had begun the application process for our second OGDP (“Genesis 2”). On February 1, 2024, the Burnett and Oasis locations within Genesis 1 were approved by the Weld County hearings officer for the Genesis 1 WOGLA permits. Genesis 1 and Genesis 2 encompass up to 72 gross wells and 48 gross wells, respectively, from two pads each, with each pad developing nine-square miles of subsurface minerals. The two pads in Genesis 1 are expected to develop up to 18 gross three-mile lateral wells and 54 gross two-mile lateral wells. In Genesis 2, the two pads are expected to develop up to 16 and 32 gross three-mile lateral wells, respectively. Following the September 15, 2023 submission of Genesis 1 with the Colorado Energy and Carbon Management Commission (“CECMC”) for the Burnett and Oasis locations, a hearing before the CECMC was held on March 13, 2024, in which the Genesis 1 OGDP received unanimous approval of the commissioners. The following table summarizes the permitting status of our identified well locations with respect to our Genesis Assets as of December 31, 2024: Expected Three Mile Lateral Count Expected Two Mile Lateral Count WOGLA Approved 18 54 CECMC Approved 18 54 CECMC Fully Permitted (1) — 8 (1) Represents the Genesis Bolt-on Assets only, which were acquired in February 2024. For more information regarding regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations below. 6 Central Weld Assets On January 11, 2024, we entered into the NRO Agreement to acquire the Central Weld Assets, located in the DJ Basin in Weld County, Colorado for total consideration of $94.5 million, subject to certain closing price adjustments and other customary closing conditions. On August 15, 2024, we and NRO agreed to amend certain terms of the NRO Agreement, pursuant to which, total consideration of the NRO Acquisition was reduced to $84.5 million in cash, subject to certain closing price adjustments and other customary closing conditions. On October 1, 2024, we closed the NRO Acquisition and paid $49.6 million to the sellers in cash, using cash on hand, the proceeds from the issuance of Common Stock, and a portion of the proceeds from the issuance of the Senior Convertible Note (as defined herein). We completed the final settlement with NRO in December 2024, which resulted in a final purchase price of $55.5 million. As of December 31, 2024, the Central Weld Assets cover approximately 5,640 net leasehold acres, on and under approximately 6,000 gross acres and 63 gross proved undeveloped locations, all of which have approved well permits and 26 gross operated horizontal wells. Since the closing of the NRO Acquisition, we have added 14 additional gross proved undeveloped locations to the Central Weld Assets. Approximately 85% of the net leasehold of our Central Weld Assets are held by production and almost all of the acreage is leased from private landowners. The Central Weld Assets fee leases are burdened with average royalties of 20%. The remaining 15% of the Central Weld Assets acreage not held by production have varying expiration dates, some with options to extend ranging from one to three 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 plan to begin executing the development plan of our Central Weld Assets at the end of the first quarter of 2025 by drilling 14 gross wells on the Rusch pad. We expect these wells to come online at the beginning of the third quarter of 2025. We then plan to drill seven gross wells on our Noble pad, which should come online in the third quarter of 2025. Additionally, we plan to drill up to a total of 57 gross wells in 2025 and up to 51 gross wells in 2026, with all proved undeveloped reserves scheduled to be converted to developed status within five years. 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. Prior to the Shelduck wells, we had no operating history of drilling successfully producing oil and natural gas wells. 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. We have historically incurred significant losses and experienced negative cash flow and have not generated any revenue related to the exploration and production of oil and natural gas assets to date. Ensuring that permits are received in a timely manner is critical to our development plan. As of December 31, 2024, all 63 of the 77 gross undeveloped Central Weld Asset locations are WOGLA approved and CECMA approved and permitted. For more information regarding regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations. Reserves Our reserve estimates as of December 31, 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. Additionally, we did not have any estimated proved reserves as of December 31, 2023. 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. For the year ended December 31, 2024, SEC Prices, inclusive of adjustments, used in the calculations were $74.63 per Bbl of oil, $1.60 per Mcf of natural gas, and $21.63 per Bbl of NGLs. The following table presents our estimated proved reserves by category as of December 31, 2024: Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) MBoe (1) PV-10 Standardized Measure (In thousands) Proved developed producing 1,967 4,887 600 3,382 Proved developed non-producing 1,782 4,419 536 3,054 Total proved developed 3,749 9,306 1,136 6,436 Proved undeveloped 10,594 31,932 3,767 19,683 Total proved 14,343 41,238 4,903 26,119 $ 303,159 $ 255,142 (1) Assumes a ratio of 6 MMcf of natural gas per MBoe. 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 the Standardized Measure of Discounted Future Net Cash Flows (“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 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. 7 The following table provides a reconciliation of the Standardized Measure to the PV-10 of our estimated proved reserves for the period presented: Year Ended December 31, 2024 (In thousands) Standardized Measure $ 255,142 Present value of future income taxes discounted at 10% 48,017 PV-10 $ 303,159 Proved Developed Reserves Proved developed oil and natural gas reserves are reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. The following table presents the changes in our estimated proved developed reserves during the year ended December 31, 2024: Total (MBoe) Proved developed reserves as of January 1, 2024 — Acquisitions of reserves 6,606 Production (170 ) Proved developed reserves as of December 31, 2024 6,436 As of December 31, 2024, our estimated proved developed reserves are 6.4 MMBoe, which are comprised of the proved developed reserves acquired in the NRO Acquisition, which closed on October 1, 2024. Proved Undeveloped Reserves PUD 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. PUD 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 PUD reserves during the year ended December 31, 2024: Total (MBoe) Proved undeveloped reserves as of January 1, 2024 — Converted to proved developed reserves (2,819 ) Acquisitions of reserves 22,324 Revisions to previous estimates 178 Proved undeveloped reserves as of December 31, 2024 19,683 As of December 31, 2024, our estimated PUD reserves are 19.7 MMBoe, which includes reserve acquisitions of 22.3 MMBoe, approximately 19.7 MMBoe of which relate to the NRO Acquisition, which closed on October 1, 2024. The remaining acquired reserves were our Shelduck locations, which we acquired in February 2024 and began developing in August. These reserves were converted to proved developed non-producing by year end as a result of successful drilling efforts. Management reviews all PUD reserves on an annual basis to ensure an appropriate plan for development exists. As per SEC rules, all of our PUD reserves are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves, unless the reserves are associated with an existing producing zone. We expect that development costs associated with our estimated PUD reserves as of December 31, 2024 will require us to invest an additional $290.0 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 PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUD reserves may not ultimately be developed or produced. 8 Preparation of Reserves Estimates Our proved reserve estimates as of December 31, 2024 have been prepared by CG&A, an independent Petroleum Reserve Evaluation Firm. No director, officer, or key employee of CG&A has any financial ownership in us or any of our affiliates. CG&A’s compensation for the 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. The estimates of our reserves presented in the CG&A reserve report were overseen by W. Todd Brooker. Our full reserve report as of December 31, 2024, prepared by CG&A, should be read in its entirety, and is attached as Exhibit 99.1 to this Annual Report. 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. His reserve reports are routinely used for public company SEC disclosures. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honors 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 Society of Petroleum Engineers (“SPE”) and the Society of Petroleum Evaluation Engineers (“SPEE”). CG&A was selected for their historical experience and geographic expertise in engineering similar resources. The technical and economic data used in the estimation of our reserves include, but are not limited to, lease positions, estimated working and net revenue interests, indicative drilling and completion costs, facility and pipeline costs, expected operating expenses and schedules for proposed drilling and permitting, as well as regional production, well information and directional surveys. Our independent reserve engineers use this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis and analogy. The reserve volumes and their respective classifications and categorizations were estimated by performance methods, volumetric methods, analogy, or combination of methods. Performance methods generally included decline-curve analysis and material balance analysis where representative data was available. Volumetric estimates generally included a combination of geological and engineering interpretations, while analogy methods included reserve estimates from historical performance of similar wells and reservoirs in the field or nearby fields. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Refer to Risk Factors— 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 . Internal Controls over Reserve Estimates and Reserve Estimation Procedures We have assembled an internal technical team composed of reservoir engineers, geologists, land, and management members, which meet with the independent reserve engineers periodically during the period covered by the reserve reports to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for its properties such as ownership interest, oil and natural gas production, well data, commodity prices and operating and development costs. 9 The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following: ● review and verification of historical production data of offset operators, working interests, net revenue interest, lease operating statements, capital costs, severance and ad valorem taxes, which as of this filing, has been derived from data from offset third-party operators; ● verification of property ownership by our land department; ● overseeing the preparation of reserve estimates by our Executive Vice President of Operations; ● review by our President of all of our reserves, including the review of all significant reserve changes and all new proved undeveloped reserves additions; and ● direct reporting responsibilities and final approval by our Chief Executive Officer and President. Qualifications of Technical Persons 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. Mr. Smith is responsible for reservoir engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing our independent reserve engineers during the preparation of our 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 Society of Petroleum Engineers. 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 15 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. Production, Average Sales Prices, and Production Costs Our production volumes, average sales prices and average production costs are as follows: Years Ended December 31, 2024 2023 Production: Oil (MBbls) 96 — Natural gas (MMcf) 245 — NGL (MBbls) 33 — Total production (MBoe) 170 — Average sales price (excluding effects of derivatives): Oil (per MBbls) $ 68.60 $ — Natural gas (per MMcf) $ 2.25 $ — NGL (per MBbls) $ 24.03 $ — Average price (per MBoe) $ 46.70 $ — Average lease operating expenses (per Boe) $ 7.44 $ — For additional information, refer to Part II - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . 10 Drilling Activity The following table sets forth a summary of our operated development and exploratory drilling well activity for the year ended December 31, 2024. We did not have any development or exploratory drilling activities during the year ended December 31, 2023. Gross wells are the total number of wells we drilled in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells. Exploratory Wells Development Wells (1) Total Gross Net Gross Net Gross Net Productive wells (2) — — 8.0 6.33 8.0 6.33 Dry wells (3) — — — — — — (1) Development wells consist of wells completed and/or turned to sales during the period, regardless of when drilling was initiated. (2) A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled. All of our drilled development productive wells have come online in February 2025. (3) A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be productive, as opposed to the year the well was drilled. 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 information about our productive wells as of December 31, 2024. We did not have any productive wells as of December 31, 2023. Oil Natural Gas Total Operated Gross Net Gross Net Gross Net Gross Net Productive wells 8.0 6.33 8.0 6.33 8.0 6.33 8.0 6.33 Acreage The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2024. 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 6,147 5,738 30,748 18,031 36,895 23,769 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. Approximately 15,810 net acres, or 66%, of our total net acres may expire in the next three years if production is not established or if we do not extend lease terms. 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. 11 The following table sets forth the undeveloped acreage, as of December 31, 2024, 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 2025 Expiring 2026 Expiring 2027 Expiring 2028 and Beyond Gross Net Gross Net Gross Net Gross Net DJ Basin 2,345 1,451 19,640 11,640 5,866 2,720 2,896 2,221 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 Agreement (as defined below), 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 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 did not have any producing wells prior to the NRO Acquisition, which closed on October 1, 2024. Following the NRO Acquisition, during the fourth quarter of 2024, two of our largest customers accounted for approximately 80% and 15% of our oil, natural gas, and NGL revenues. Those same two customers accounted for approximately 78% and 20% of our accrued oil, natural gas, and NGL revenues. We do not believe the loss of any single purchaser would materially impact our operating results, as crude oil, natural gas, and NGL are fungible products with well-established markets and numerous purchasers. Delivery Commitments The Company does not have any delivery commitments as of December 31, 2024 or 2023. 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. 12 International Events International events, such as the conflict between Russia and Ukraine, the announcement of production curtailment by the Organization of the Petroleum Exporting Countries (“OPEC”) and the recent conflict in the Middle East, have contributed to increases and volatility in the prices for oil and natural gas. Such volatility, coupled with an increased cost of capital, due in part to rates of inflation and high interest rates, may lead to a more difficult investing and planning environment for us. These and other factors beyond our control could adversely affect the Company’s operations, earnings and cash flows for any period. Refer to Risk Factors— 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. 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 which may be drilled in an area and 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 the same regulatory requirements and restrictions that 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. For example, in November 2020, pursuant to Colorado Senate Bill 19-181, the CECMC imposed a number of new and amended requirements on our operations. These requirements, and any other new requirements of the 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. 13 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 risks in the U.S., including climate change-related pledges made by certain administrations. During his administration, former President Biden issued several executive orders focused on addressing climate change, which may impact the costs to produce, or demand for, oil and natural gas. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the U.S.: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which established a roadmap to net zero emissions in the U.S. by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide. Given the directives issued by the current administration to withdraw the U.S. from the Paris Agreement on climate change, it is likely that these policies will be rescinded by the present administration. 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 (“DI”) 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. 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. 14 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 $1,472,546 (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. 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. 15 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 (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. 16 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. 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 nonhazardous 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 nonhazardous 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 nonhazardous 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 neighboring 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. 17 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, 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. 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. 18 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. 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. 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. 19 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. Smaller reporting companies will be required to incorporate discussion of these risks in filings beginning in fiscal year 2027 and will not be required to report GHG emissions data. Large accelerated filers and accelerated filers will be required to incorporate such discussion in fiscal years 2025 and 2026, respectively, as well as disclose Scope 1 and 2 GHG emissions, if material, in fiscal years 2026 and 2027, and provide third party attestation reports related to such emissions beginning in fiscal years 2029 and 2031. However, this rule has been challenged and, on February 11, 2025, the Acting Chairman of the SEC stated that the commission will pause litigation on this rule. 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. 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 is $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. On February 4, 2025, a joint resolution was proposed to void this rule under the Congressional Review Act. Even if the joint resolution is approved, it may not eliminate the waste methane fee because the fee was mandated by the IRA. 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. 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. We will use hydraulic fracturing 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. 20 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 Occupational Safety and Health Act (“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. 21 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. Most recently, the CECMC is considering a draft rulemaking 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, DI communities, and “cumulatively impacted communities.” The draft rules would also set GHG emissions intensity targets for oil and natural gas operators and require regulators to consider such 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, 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 DI 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 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. 22 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. Cryptocurrency Mining In 2023, we generated all of our revenue through our cryptocurrency mining activities from assets we acquired in the Merger. On January 23, 2024, we closed the Crypto Sale in which we sold all of our Mining Equipment and the Atlas MSA. Refer to Recent Developments—Sale of Crypto Assets. Accordingly, we do not currently have and do not expect to have any cryptocurrency mining operations in the future. Following the Crypto Sale, our exposure to the market prices of cryptocurrencies is limited to the ability of the Crypto Purchaser to pay the deferred purchase price pursuant to the Crypto Divestiture Agreement. Refer to Recent Developments—Sale of Crypto Assets, Risk Factors—We may not realize the full benefit of the Crypto Sale for a variety of reasons, including the inability of the Crypto Purchaser to pay the Deferred Purchase Price due to a decrease in the price of Bitcoin or the actions of third parties and the Crypto Divestiture Agreement. Pre-Merger cryptocurrency mining activities during 2022 consisted of participation in mining pools that pooled the resources of groups of miners and split cryptocurrency rewards earned according to the “hashing” capacity each miner contributes to the mining pool. Pre-Merger, Creek Road ceased cryptocurrency mining operations in mid-2022, and reinitiated such operations upon entering into the Atlas MSA in February 2023, pursuant to which Atlas hosted, operated, and managed the Mining Equipment, and we received payment in U.S. dollars for the daily net mining revenue representing the dollar value of the cryptocurrency award generated less power and other costs. Under the Atlas MSA, we did not own, control or take custody of any Bitcoin produced by the Mining Equipment. Instead, Atlas, as service provider, retained all Bitcoin rewards, deducted a hosting service fee from the monthly total mined currency produced by our miners and remitted the net proceeds of the mined currency to us in cash. The Merger was accounted for as a reverse asset acquisition; as a result, our cryptocurrency mining operations are reported as commencing on May 3, 2023, concurrent with the Merger, and prior revenues and expenses of Creek Road related to cryptocurrency mining activities are not presented in Part II. Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations or the accompanying financial statements. Intellectual Property We do not currently own any intellectual property. Employees As of December 31, 2024, we employed 19 full-time employees. We have never experienced a work stoppage, and believe we maintain positive relationships with our employees. Offices As of December 31, 2024, we have leased office space in Houston, Texas, where our principal offices are located, and in Denver, 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.” 23