Prairie Operating Co. 10-K/A

Item 1. Business The Company Prairie Operating Co. (the “Company”) is an independent oil and gas company focused on the acquisition and development of crude oil, natural gas and natural gas liquids (“NGLs”). We currently hold attractive acreage in the Denver-Julesburg Basin in Colorado (the “DJ Basin”) that our experienced management team intends to develop, deploying next-generation technology and techniques in an environmentally efficient manner. 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, 2023, all of the Company’s exploration and production (“E&P”) assets were acquired in the Exok Transaction (as defined herein) and Exok Option Purchase (as defined herein) and consist of certain oil and gas leasehold interests with no existing oil and gas production or revenue. In February 2024, we acquired the Genesis Bolt-on Assets (as defined herein), offsetting our existing assets. In all, the total Genesis Assets (as defined herein) include 24,351 net mineral acres in, on and under 37,985 gross acres. In addition, in January 2024, we entered into a definitive agreement with NRO (as defined herein) to acquire the Central Weld Assets (as defined herein). We have no current drilling or completion operations. As such, our current activities are focused on obtaining requisite permits to begin drilling wells on our Genesis Assets, as well as funding and closing the NRO Acquisition, which we anticipate in the first half of 2024. Additionally, in 2023, we also engaged in cryptocurrency mining operations. In January 2024, we divested all of our cryptocurrency mining assets. See “— Recent Developments ” for more information. Background On May 3, 2023, pursuant to 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 Operating Co., LLC (“Prairie LLC”), 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 consummation of the Merger, the Company changed its name from “Creek Road Miners, Inc.” to “Prairie Operating Co.” The Company traded under its former name and ticker symbol “CRKR” until October 16, 2023. From October 16, 2023 to November 12, 2023, the Company traded under symbol “CRKRD,” a transitionary ticker symbol. The Company began trading under its current ticker symbol, “PROP,” on November 13, 2023. On December 21, 2023, the Company received approval to list its common stock on the Nasdaq Capital Market securities exchange (“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. 2 Prior to the consummation of the Merger, the Company effectuated a series of restructuring transactions (the “Restructuring Transactions”) in the following order and issued an aggregate of 3,860,898 shares of common stock (excluding shares reserved for issuance and unissued subject to certain beneficial ownership limitations) and 4,423 shares of Series D Preferred Stock (as defined herein): (i) the Company’s Series A preferred stock, Series B preferred stock and Series C preferred stock, plus accrued dividends, were converted into shares of common stock; (ii) the Company’s 12% senior secured convertible debentures (the “Original Debentures”), plus accrued but unpaid interest and a 30% premium, were exchanged, in the aggregate, for (a) 12% amended and restated senior secured convertible debentures (collectively, the “AR Debentures”), each in the principal amount of $1,000,000, in substantially the same form as their respective Original Debentures, (b) shares of common stock and (c) shares of Series D preferred stock; (iii) accrued fees payable to our board of directors (the “Board”) in the amount of $110,250 were converted into shares of common stock; (iv) accrued consulting fees of the Company in the amount of $318,750 payable to Bristol Capital, LLC (“Bristol Capital”) were converted into shares of common stock; and (v) all amounts payable pursuant to certain convertible promissory notes were converted into shares of common stock. Prior to the closing of the Merger (the “Closing”), the Company’s then-existing warrants to purchase shares of common stock, warrants to purchase shares of Series B preferred stock and options to purchase shares of common stock were cancelled and retired and ceased to exist without the payment of any consideration to the holders thereof. At the effective time of the Merger (the “Effective Time”), all 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. At the Effective Time, the Company assumed and converted options to purchase membership interests of Prairie LLC outstanding and unexercised as of immediately prior to the Effective Time into non-compensatory options to acquire an aggregate of 8,000,000 shares of common stock (the “Non-Compensatory Options”) for $7.14 per share, which are only exercisable if specific production hurdles are achieved, and the Company entered into amended and restated non-compensatory option agreements (collectively, the “Option Agreements”) with each of Gary C. Hanna, Edward Kovalik, Paul Kessler and a third-party investor. An aggregate of 2,000,000 Non-Compensatory Options are subject to be transferred to the Series D PIPE Investors (as defined herein), based on their then percentage ownership of Series D Preferred Stock to the aggregate Series D Preferred Stock outstanding and held by all Series D PIPE Investors as of the closing date of the Merger, if the Company does not meet certain performance metrics by May 3, 2026. In addition, in connection with the Closing, the Company consummated the purchase of oil and gas leases from Exok, Inc. (“Exok”), including all of Exok’s right, title and interest in, to and under certain undeveloped oil and gas leases located in Weld County, Colorado, together with certain other associated assets, data and records, consisting of approximately 3,157 net mineral acres in, on and under approximately 4,494 gross acres from Exok for $3.0 million pursuant to the Amended and Restated Purchase and Sale Agreement, dated as of May 3, 2023 (the “Exok Agreement”), by and among the Company, Prairie LLC and Exok (the “Exok Transaction”). To fund the Exok Transaction, the Company sold an aggregate of approximately $17.4 million of Series D Preferred Stock with a stated value of $1,000 per share and convertible into shares of common stock at a price of $5.00 per share, Series A warrants to purchase 3,475,250 shares of common stock at an exercise price of $6.00 per share (“Series D A Warrants”) and Series B warrants to purchase 3,475,250 shares of common stock at an exercise price of $6.00 per share (“Series D B Warrants” and, collectively with the Series D A Warrants, the “Series D PIPE Warrants”) in a private placement (the “Series D PIPE”) pursuant to securities purchase agreements, dated May 3, 2023, by and between the Company and each of the investors thereto (the “Series D PIPE Investors”). 3 On August 14, 2023, Prairie LLC exercised its option under the Exok Agreement to purchase additional oil and gas leases, including all of Exok’s right, title and interest in, to and under certain undeveloped oil and gas leases located in Weld County, Colorado, together with certain other associated assets, data and records, consisting of approximately 20,328 net mineral acres in, on and under approximately 32,695 gross acres from Exok. We refer to the assets acquired in these transactions in 2023 as the “Initial Genesis Assets.” The Company paid $18.0 million in cash to Exok and issued equity consideration to certain affiliates of Exok, consisting of (i) 670,499 shares of common stock and (ii) Exok Warrants providing the right to purchase 670,499 shares of common stock at $7.43 per share. To fund the Exok Option Purchase, the Company entered into a securities purchase agreement with Narrogal Nominees Pty Ltd ATF Gregory K O’Neill Family Trust (the “Series E PIPE Investor”) on August 15, 2023, pursuant to which the Series E PIPE Investor agreed to purchase, and the Company agreed to sell to the Series E PIPE Investor, for an aggregate of $20.0 million, securities consisting of (i) 39,614 shares of common stock, (ii) 20,000 shares of Series E preferred stock, par value $0.01 per share, with a stated value of $1,000 per share, convertible into shares of common stock at a price of $5.00 per share (“Series E Preferred Stock”), and (iii) Series E A Warrants to purchase 4,000,000 shares of common stock and Series E B Warrants to purchase 4,000,000 shares of common stock, each at a price of $6.00 per share (collectively, the “Series E PIPE Warrants”), in a private placement (the “Series E PIPE”). The Exok Option Purchase and the Series E PIPE closed on August 15, 2023. On September 18, 2023, the Company submitted its initial permit application with the Colorado Energy and Carbon Management Commission for the Genesis Oil & Gas Development Plan (“OGDP”) in Weld County, Colorado. The Genesis OGDP encompasses seventy-two (72) wells on two (2) pads, developing 9-square miles of subsurface minerals in rural Weld County, Colorado. The two (2) pads, the Burnett and Oasis, will develop eighteen (18) three-mile lateral wells and fifty-four (54) two-mile lateral wells, respectively. On October 13, 2023, the holders of the AR Debentures elected to convert their AR Debentures into an aggregate of 400,666 shares of common stock. On October 16, 2023, the Company effected a reverse stock split of outstanding shares of the Company’s common stock at an exchange ratio of 1:28.5714286 (the “Reverse Stock Split”). The share counts listed above have been retroactively adjusted to reflect the Reverse Stock Split. On November 13, 2023, Narrogal Nominees Pty Ltd ATF Gregory K O’Neill Family Trust (“O’Neill Trust”) delivered notice to the Company of the exercise of Series D B Warrants to purchase 2,000,000 shares of common stock at an exercise price of $6.00 per share for total proceeds to the Company of $12 million (the “Warrant Exercise”). The Company intends to use the proceeds from the Warrant Exercise for general working capital purposes, which may include drilling activity or opportunistic acquisitions. Each of the warrants held by the O’Neill Trust, as well as the Series D Preferred Stock and Series E Preferred Stock was subject to a limitation on exercise or conversion, as applicable, if as a result of such exercise or conversion, the holder would own more than 4.99% of the outstanding shares of common stock (the “Beneficial Ownership Limitation”), which may be increased by the holder upon written notice to the Company, to any specified percentage not in excess of 9.99% (the “Beneficial Ownership Limitation Ceiling”). In connection with the Warrant Exercise, the O’Neill Trust entered into an agreement with the Company pursuant to which it amended the terms of each of its Series D PIPE Warrants and Series E PIPE Warrants to increase the Beneficial Ownership Limitation Ceiling from 9.99% to 25% and gave notice to the Company that it was increasing its Beneficial Ownership Limitation to 25% with respect to each of its remaining warrants. The Beneficial Ownership Limitation Ceiling on the Series D Preferred Stock and Series E Preferred Stock remains at 9.99%. In December 2023, 1,172 shares of Series D Preferred Stock were converted by the holders into 234,424 shares of common stock. Additionally, 41,980 shares of common stock were issued in December in connection with a cashless exercise of Series D A Warrants. Recent Developments NRO Acquisition On January 11, 2024, the Company entered into an asset purchase agreement (the “NRO Agreement”), by and among the Company, Prairie LLC, Nickel Road Development LLC and Nickel Road Operating LLC (“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”), which will be released to Seller upon the earlier of the closing date and August 15, 2024 (the “Outside Date”). Portions of the Deposit are subject to earlier release under certain circumstances if the closing has not occurred on or prior to June 17, 2024. The NRO Agreement provides that the closing of the NRO Acquisition is subject to customary conditions precedent, including (i) the accuracy of the representations and warranties of each party (subject to specified materiality standards), (ii) compliance by each party in all material respects with their respective covenants, (iii) that no event of Force Majeure or Material Adverse Effect (in each case as defined in the NRO Agreement) shall have occurred, in each case the result of which is that the Company is unable to secure satisfactory financing with respect to the Transaction (as defined in the NRO Agreement), and (iv) the Registration Statement (as defined in the NRO Agreement) has been declared effective with the SEC on or before the Outside Date. The NRO Agreement contains customary title and environmental defect mechanisms with respect to the Central Weld Assets, including purchase price adjustments and termination rights. The NRO Agreement may be terminated under circumstances as described in the NRO Agreement, including (i) with the mutual written consent of the Company and NRO, (ii) by the Company, upon the occurrence of an event of Force Majeure or Material Adverse Effect, in each case the result of which is that the Company determines, in its reasonable discretion, that it is, or will be, unable to secure satisfactory financing with respect to the Transaction, or (iii) in the event that the NRO Acquisition has not been consummated on or before the Outside Date. 4 The parties have made customary representations and warranties in the NRO Agreement. The NRO Agreement also contains customary covenants and agreements, including covenants and agreements relating to (a) the conduct of NRO’s business during the period between the execution of the NRO Agreement and closing of the NRO Acquisition and (b) the efforts of the parties to cause the NRO Acquisition to be completed, including actions which may be necessary to facilitate a satisfactory financing transaction by the Company. The parties have agreed to indemnify each other for certain liabilities following the closing on the NRO Acquisition (as further set forth in the NRO Agreement), subject to the limitations set forth in the NRO Agreement. The assets and the operations of NRO include Oil and Gas Leases, Mineral Fee Interests, producing and disposal Wells, and Units, in each case as defined in the NRO Agreement and located in the DJ Basin in Weld County, Colorado, as well as appurtenant records and equipment and other properties. The Company expects the NRO Acquisition to close on or before the Outside Date, subject to customary closing conditions, with an economic effective date of February 1, 2024. The Company expects to fund the transaction through a combination of public and/or private issuance of common stock, cash on hand, and proceeds from existing warrant exercises. While we expect to close the NRO Acquisition in the first half of 2024, such acquisition is subject to a number of closing conditions. Satisfaction of some of these conditions is beyond our control. If these conditions are not satisfied or waived, the NRO Acquisition will not be completed. See “ Risk Factors—Risks Related to the NRO Acquisition ” and the full text of the NRO Agreement, which is attached as Exhibit 2.2 to this Annual Report. The reserve information included in this Annual Report does not reflect the acquisition of the Central Weld Assets, since the NRO Acquisition has not yet been consummated. Sale of Crypto Assets On January 23, 2024, pursuant to an asset purchase agreement (the “the Crypto Divestiture Agreement”) between the Company and a private purchaser (the “Crypto Purchaser”), the Company sold all of its 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. The full text of the Crypto Divestiture Agreement is attached as Exhibit 2.3 to this Annual Report. In addition to the sale of the Mining Equipment, the Company assigned, and the Crypto Purchaser assumed, all of the Company’s rights and obligations under the Master Services Agreement, dated February 16, 2023, by and between Atlas Power Hosting, LLC (“Atlas”) and the Company (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. As collateral security for the prompt and complete payment and performance in full of the Crypto Purchaser’s obligations under the Crypto Divestiture Agreement, including payment of the Deferred Purchase Price, the Company obtained a security interest in, among other things, the Mining Equipment and the Atlas MSA. In addition, the Crypto Divestiture Agreement requires the Crypto Purchaser to operate the Mining Equipment in the ordinary course of business and maintain in effect the Atlas MSA until the Deferred Purchase Price is paid in full. Since payment of the Deferred Purchase Price is dependent on the revenue generated by the Mining Equipment, we cannot predict the timing of when we will receive the Deferred Purchase Price, if at all. See “ 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. ” 5 Genesis Bolt-on Acquisition On February 5, 2024, the Company acquired a 1,280-acre drillable spacing unit (“DSU”) and eight proved undeveloped (“PUD”) drilling locations in the DJ Basin (the “Genesis Bolt-on Assets”) from a private seller for $900,000. We refer to the Initial Genesis Assets and the Genesis Bolt-on Assets, collectively, as the “Genesis Assets.” The Genesis Bolt-on Assets offset the Initial Genesis Assets held by the Company in northern Weld County, Colorado. The reserve information included in this Annual Report does not reflect the acquisition of the Genesis Bolt-on Assets as they were acquired subsequent to December 31, 2023. Nature of Business E&P We are an independent oil and gas company focused on the acquisition and development of crude oil, natural gas and natural gas liquids. We currently hold attractive acreage in the DJ Basin of Colorado that our experienced management team intends to develop, deploying next-generation technology and techniques in an environmentally efficient manner. 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 associated 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. The Initial Genesis Assets Prairie acquired the Initial Genesis Assets in the Exok Transaction and the Exok Option Purchase, which includes the following assets: ● all of Exok’s right, title and interest in, to and under the fee oil and gas leases described more particularly in the Exok Agreement, including all working interests, operating rights, record title interests and other interests of every kind and character (the “Fee Leases”), that include and convey no less than a 75% net revenue interest (“NRI,” being the share of production of all hydrocarbons produced, saved and sold, after all burdens, such as royalty and overriding royalty, have been deducted from the working interest) in each Fee Lease; ● all of Exok’s right, title and interest in, to and under the State of Colorado Oil and Gas Lease described more particularly in the Exok Agreement, including all working interests, operating rights, record title interests and other interests of every kind and character (the “State Leases”), that include and convey no less than a 77.5% NRI in the State Leases; ● 100% of Exok’s leasehold interest (Fee Leases and State Leases collectively referred to as the “Leases”) in approximately 23,485 net mineral acres in, on and under approximately 37,189 gross acres located in Weld County, Colorado, as described more particularly in the Exok Agreement (the “Lands”); ● to the extent transferable, Exok’s interests in and under all contracts, agreements and instruments by which the other Initial Genesis Assets are bound or that relate to or are used or useful in connection with the ownership, development or operation of the Leases or the Lands, to the extent applicable to the Leases or Lands, including all surface use agreements, surface rights, surface permits and other similar rights and instruments; and ● all of Exok’s records, files and geological and geophysical data directly related to the Initial Genesis Assets, including without limitation all logs, core analyses, formation tests, films, surveyors’ notes, plane table sheets, shot point data bases, land files, contract files, lease files, title files (including title reports, title opinions, runsheets, abstracts, evidence of bonus and rental payments), maps, surveys and data sheets. The assets are undeveloped oil and gas leasehold acreage located in northern Colorado, in Weld County covering approximately 37,030 gross acres and 23,485 net acres. The operating area is rural and free of development. Access to the leases is by paved and dirt country roads and private road access. Approximately 70% of the net leasehold of our Initial Genesis Assets are leased from private landowners, with the remaining 30% under State of Colorado leases. None of the Initial Genesis Assets are subject to federal leases. All of the Initial Genesis 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 fee leases are burdened with total royalties of 25%. The State of Colorado leases are burdened with total royalties of 22.5%. 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. 6 The Initial 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 the Company’s DJ Basin operating area, there are over 1,300 legacy vertical wells, with Chevron Corporation, Civitas Resources, Inc., Verdad Resources LLC, Bison Oil and Gas, EOG Resources, Inc. and Samson Energy Company, LLC operating a substantial number of such wells. 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 have included Chevron Corporation, Civitas Resources, Inc., Verdad Resources, 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, Outrigger Energy II LLC, Rimrock Energy Partners LLC and Roaring Fork Midstream LLC. Development Plan and Permitting We believe that we are ideally positioned to execute on our development plan of our Genesis Assets and the Central Weld Assets after the closing of the NRO Acquisition. The Board has authorized and approved the Company to drill up to 30 wells in 2024 and 45 wells in 2025 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 gas. The Company has no operating history related to the exploration and production of oil and gas assets or drilling producing oil and 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 the Company’s 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 gas assets to date. Further, we may be unable to consummate the NRO Acquisition and therefore be unable to acquire the Central Weld Assets in connection therewith, for which we are dependent on for generating initial revenue. A failure to successfully develop and produce our assets or the failure to consummate the NRO Acquisition, may result in the loss of our investment in the Genesis Assets and affect our ability to execute our development plan. Critical to our development plan is an effective approach to ensuring well permits are received in a timely manner. 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 wells and 48 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 three-mile lateral wells and 54 two-mile lateral wells. In Genesis 2, the two pads are expected to develop up to 16 and 32 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 March 15, 2024: Genesis Assets Expected Three Mile Lateral Count Expected Two Mile Lateral Count WOGLA Approved (1) 18 54 CECMC Approved (1) 18 54 CECMC Fully Permitted (2) — 8 (1) Excludes fully permitted wells. (2) Represents Genesis Bolt-on Assets only, which were acquired in February 2024. For more information regarding regulations affecting our permitting, see “ Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations. ” 7 Summary of Our Reserve Estimates The Company’s estimated possible reserves as of December 31, 2023, as shown in the following table, have been prepared by Cawley, Gillespie & Associates Inc. (“CG&A”), an independent Petroleum Reserve Evaluation Firm, in accordance with the rules and regulations of the SEC utilizing SEC prices. The Company had no proved reserves as of December 31, 2023 and had no reserves as of December 31, 2022. The reserves information set forth below does not include the Genesis Bolt-On Assets, which were acquired in February 2024. CG&A’s reserve report as of December 31, 2023, which should be read in its entirety, is attached as Exhibit 99.1 to this Annual Report. As of December 31, 2023 Reserve Data (1) Estimated possible reserves Oil (MBbl) 92,733.3 Natural gas (MMcf) 181,542.3 Natural gas liquids (MBbl) 28,834.5 Total estimated possible reserves ( M Boe) (2) 151,824.9 Percent oil and liquids 80 % (1) Possible reserves were calculated using SEC prices, which were $78.22 per Bbl for oil and $2.637 per Mcf for natural gas for the year ended December 31, 2023. Adjustments were made for location and grade. (2) Assumes a ratio of 6 MMcf of natural gas per MBoe. Preparation of reserves estimates. CG&A is an independent oil and natural gas consulting 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. 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. Under SEC rules, possible reserves are reserves which, by analysis of geoscience and engineering data, are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. The technical and economic data used in the estimation of our possible 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. 8 The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “ Risk Factors— 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 and Qualifications of Technical Persons In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (the “Reserve Standards”) and guidelines established by the SEC, CG&A estimated the Company’s possible undeveloped reserves as of December 31, 2023. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Reserve Standards. See “ —Preparation of Reserve Estimates .” The Company maintains an internal staff of a petroleum engineer and consulting engineer and geoscience professionals who work closely with its independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate its proved and possible reserves relating to its assets. The Company’s internal technical team members met with independent reserve engineers periodically during the period covered by the reserve reports to discuss the assumptions and methods used in the proved and possible reserve estimation process. The Company provides 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. The preparation of the Company’s proved and possible reserve estimates is completed in accordance with the Company’s 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 the Company’s land department; ● overseeing the preparation of reserve estimates by the Company’s Executive Vice President of Operations; ● review by the Company’s President of all of the Company’s reserves, including the review of all significant reserve changes and all new proved and possible undeveloped reserves additions; and ● direct reporting responsibilities and final approval by the Company’s Chief Executive Officer and the Company’s President. Bryan Freeman, our Executive Vice President of Operations, 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. Freeman is primarily responsible for overseeing the preparation of both our internal and external reserve estimates. Mr. Freeman 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. His qualifications include a Masters and Bachelor of Science degrees in Engineering from University of Texas; a member of the Society of Petroleum Engineers; and more than 19 years of practical experience in estimating and evaluating reserve information with more than 10 of those years overseeing, estimating and evaluating reserves. 9 Customers As the Company has no producing wells, it does not have any customers for its E&P business as of and for the year ended December 31, 2023 or as of December 31, 2022 and for the period from June 7, 2022 (date of inception) through December 31, 2022. Delivery Commitments The Company does not have any delivery commitments as of December 31, 2023 or 2022. Productive Wells The Company does not have any productive wells as of December 31, 2023 or 2022. 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, 2023. The Company did not have any developed or undeveloped acreage for which it owned a working interest as of December 31, 2022. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary. This summary does not reflect the Genesis Bolt-On Assets that were acquired in February 2024. Developed Acres Undeveloped Acres Total Acres Gross Net Gross Net Gross Net DJ Basin — — 37,030 23,485 37,030 23,485 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 17,419 net acres, or 74%, of the Company’s 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. The following table sets forth the undeveloped acreage, as of December 31, 2023, that 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 2024 Expiring 2025 Expiring 2026 Expiring 2027 and Beyond Gross Net Gross Net Gross Net Gross Net DJ Basin 8,313 6,598 4,023 2,567 15,649 8,254 9,045 6,067 Drilling Activity The Company has not had any development or exploratory drilling activities as of December 31, 2023 or 2022. 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. 10 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. Further, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 80% of our estimated possible reserves as of December 31, 2023 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. During the year ended December 31, 2023, the daily NYMEX WTI oil spot price ranged from a high of $93.67 per Bbl to a low of $66.61 per Bbl, and the NYMEX natural gas HH spot price ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu. See “ Risk Factors— We will face strong competition from other oil and gas companies. ” 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. See “ 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. 11 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. 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 United States, including climate change-related pledges made by certain administrations. President Biden has issued several executive orders focused on addressing climate change since taking office, 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 United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States 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. 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 to limit 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 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. 12 Regulation of Transportation and Sales of Oil Sales of oil, condensate and NGLs from producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future. Our sales of crude oil are affected by the availability, terms, conditions and cost of transportation services. Transportation of oil in interstate commerce by common carrier pipelines is also subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from how it affects operations of our competitors who are similarly situated. The Federal Trade Commission (“FTC”) has the authority under the Federal Trade Commission Act (“FTCA”) and the Energy Independence and Security Act of 2007 (“EISA”) to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of approximately $1,472,546 (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. 13 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 2024, the maximum penalty increased to $1,544,521 per violation per day to account for inflation. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EPAct of 2005, and subsequently denied rehearing. The rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly to: (1) use or employ any device, scheme, or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering. However, it does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. We are required to observe such anti-market manipulation laws and related regulations enforced by FERC under the EPAct of 2005 and those enforced by the Commodity Futures Trading Commission (“CFTC”) under the Commodity Exchange Act, as amended (“CEA”), and CFTC regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce, as well as the market for financial instruments on such commodity, such as futures, options, or swaps. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1,450,040 (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. 14 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. 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. 15 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. 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 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. 16 Subsurface Injections In the course of our operations, we produce water in addition to natural gas, crude oil and NGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near below-ground disposal wells used for the injection of natural gas- and oil-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies, as well as the owners of underground injection wells. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. Air Emissions The federal Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of our projects. Recently, there has been increased regulation with respect to air emissions from the oil and natural gas sector. In June 2016, the EPA published final rules establishing new air emission controls for methane 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. The EPA’s final rules include New Source Performance Standards (“NSPS”) at Subpart OOOOa to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on volatile organic compound (“VOC”) emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. In November 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and VOC emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA announced a final rule on December 2, 2023, which, among other things, requires the phase-out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. 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. The final emissions guidelines under Subpart OOOOc provide 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. 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. 17 Regulation of GHG Emissions In response to findings 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 United States, including certain onshore and offshore natural gas, oil and NGL production sources, which include certain of our operations. 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 proposed rule included an intended effective date of January 1, 2025, but the final rule remains pending at this time and the final effective date remains uncertain. Should this rule go into effect without major changes, it could raise our costs of regulatory compliance. 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. In addition, 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. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States 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. These goals were reaffirmed in November 2022 at the 27th Conference of the Parties (“COP27”) in Sharm-El Sheik. While there were limited announcements at COP27 with respect to the reduction of fossil fuel use, there were negotiations on emissions reduction targets and reduction of fossil fuel use amongst the international community, and such discussions continued at the 28 th Conference of the Parties. In addition, the Inflation Reduction Act of 2022 (the “IRA”), signed by 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. EPA recently issued a proposed rule to implement the waste emissions charge with a proposed effective date in 2025 for reporting year 2024 emissions. 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 exploration and production operations. 18 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 gas operators to disclose the volume of water and all chemicals used during the hydraulic fracturing process to an online registry. In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities. ESA and Migratory Birds The federal Endangered Species Act (“ESA”) and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. In June 2023, the Biden Administration announced proposed revisions concerning the procedures and criteria used for listing, reclassifying, and delisting protected species, and designating critical habitat. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases. OSHA We are subject to the requirements of the 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 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 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 gas siting; and (iv) initiated a comprehensive rulemaking to amend CECMC’s rules consistent with the agency’s revised mission. 19 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 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 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 gas interests. The CECMC has adopted significant additional regulations to implement SB 181. The legislation mandated CECMC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned or shut-in, financial assurance, wellbore integrity, and application fees. In November 2022, the CECMC completed a rulemaking on flowlines and wells that are inactive, temporarily abandoned, or shut-in and completed a rulemaking on wellbore integrity in June 2020. In January 2021, the results of a major rulemaking took effect addressing a wide range of topics, including facility siting, cumulative impacts, development approvals, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection. Those rules apply to permit applications pending on, or submitted after, the date the rule became effective, and generally to operations occurring on or after that date. The CECMC has also issued rules on financial assurance, application fees, and high-priority habitat. The financial assurance rule increased the amounts that operators are required to provide as a surety bond to ensure that wells will be properly plugged and abandoned at the end of their lifecycle. Most recently, the CECMC is considering a draft rulemaking regarding the cumulative impacts of oil and 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 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 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 gas facilities during pre-production activities, drilling, and completion. 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. 20 For example, when obtaining a permit for new multi-well pads, the State of Colorado 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 will be subject to approval by the Weld County Oil and Gas Energy Department. Prior to the application, a meeting hosted by Weld County will review all alternate locations within the development area attended by all other relevant state and local regulatory agencies. Following the pre-application meeting, a 30-day notice is submitted to Weld County stating a WOGLA application will be filed. Subsequently, a WOGLA application may be filed with a public intervention period occurring 20 days prior to a hearing. The hearing for WOGLA applications is scheduled for a minimum of 45 days from the date of submission. The Weld County hearings officer will hear the WOGLA applications for approval, and upon such approval, an order will be issued and a grading permit application must be filed prior to construction upon location. Related Insurance Once our development activities commence, we plan to maintain insurance against some risks associated with above or underground contamination that may occur as a result of these activities. However, this insurance is expected to be 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. See “ Recent Developments—Sale of Crypto Assets.” Accordingly, we currently do not expect to receive rewards in the form of cryptocurrency in the future. 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 do 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 the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” or the accompanying financial statements. Factors Affecting Profitability Our cryptocurrency business was heavily dependent on the market price of Bitcoin. In addition to the market price of Bitcoin, the price of electricity can impact the profitability of Bitcoin mining operations. The pre-Merger cryptocurrency mining operations used special cryptocurrency mining computers to solve complex cryptographic algorithms to support the Bitcoin blockchain and, in return, received Bitcoin as our reward through the third quarter of 2022. When cryptocurrency operations were re-initiated in 2023 under the Atlas MSA, we received the dollar value of Bitcoin produced net of costs as our revenue. 21 In February 2023 and as described below, Creek Road entered into the Atlas MSA. Through this contract, Creek Road sought to normalize its mining costs and agreed to pay Atlas a flat fee of $20.00 per miner to cover set-up costs and thereafter pay a monthly fee to Atlas for the quantity of electricity consumed by the miners at a rate of $0.08 per kWh. As such and upon the consummation of the Merger, the Company’s per unit cost of electricity is fixed through the term of the contract which expires on March 2, 2025. However, the cost that Atlas is required to pay its electricity provider may not be fixed and could be greater than $0.08 per kWh or $80 per MW. In such cases, it can and did shut down the Company’s miners thereby reducing both our ability to earn revenue and our electricity costs. During the year ended December 31, 2023 there were six full days whereby Atlas shut down miners due to its cost of electricity. As of December 31, 2023, approximately $12 million has been invested to acquire our miners. Creek Road paid for these miners in cash. Our mining equipment is expected to have a useful life of 2 to 5 years and depreciation of $983,788 was recognized with respect to our mining equipment for the year ended December 31, 2023. For the year ended December 31, 2023, we estimate that sunk costs, depreciation of existing equipment or replacement costs were $20,899 per Bitcoin based upon our depreciation expense in each period. For the year ended December 31, 2023, our cash operating cost was $11,392 per Bitcoin. Our Bitcoin mining operations were profitable on a cash basis due to the price of Bitcoin far exceeding our “shutdown Bitcoin price.” A breakeven analysis of the Company’s Bitcoin mining operations in terms of one Bitcoin for the year ended December 31, 2023 and key inputs for our breakeven forecast follows: Average Year Ended December 31, 2023 (1) Bitcoin price $ 32,838 Power cost per Bitcoin (11,392 ) Cash operating margin per Bitcoin 21,446 Hardware cost per Bitcoin (20,899 ) Total operating margin per Bitcoin $ 547 Key inputs to power cost: Approximate average network hash rate (EH/s) 490.0 Average energy consumption per miner (watts) (2) 3,112 Electricity cost ($ per kWh) $ 0.08 Approximate average energy consumption per Bitcoin (kWh) 142,402 (1) Calculated based on a daily average from May 3, 2023, the closing date of the Merger, to December 31, 2023. (2) This value represents the weighted average energy consumption per miner. This is a rated value as measured by the manufacturer of our miners, Bitmain. Our electricity costs are determined by multiplying the price per kWh by the number of hours in the month by the metered rated power consumption of our miners hosted by Atlas. The more miners we have hosted by Atlas, the higher our electricity costs in total are. Conversely, when the price of electricity rises to the point where Atlas shuts off our miners, we experience lower electricity costs. The daily cost of electricity under the Atlas MSA ranged from a low of $7,606 per Bitcoin to a high of $34,123 per Bitcoin for the year ended December 31, 2023. 22 The average trading price of Bitcoin under the Atlas contract was $32,838 for the year ended December 31, 2023. Our cash costs under the Atlas contract averaged $11,392 per Bitcoin in this period and was solely from the power cost of $0.08 per kWh. On average, our miners used 142,402 kWh to mine one Bitcoin during this period. There were no set-up or other costs under the Atlas MSA incurred during these periods. This resulted in an average cash operating margin of $21,446 per Bitcoin for the year ended December 31, 2023. As a result, the Company’s average cash breakeven cost to mine one Bitcoin was equal to $11,392 per Bitcoin for the year ended December 31, 2023. When including the cost of hardware, the Company’s total costs to mine one Bitcoin was $32,291 and resulted in a total operating margin of $547 per Bitcoin for the year ended December 31, 2023. In 2023, industry-wide developments, including the industry-wide fallout from the recent Chapter 11 bankruptcy filings of cryptocurrency exchange FTX (including its affiliated hedge fund Alameda Research), crypto hedge fund Three Arrows, crypto miners Compute North and Core Scientific and crypto lenders Celsius Network, Voyager Digital and BlockFi, as well as legal action taken by the SEC against Coinbase, Binance and Sam Bankman-Fried, are beyond our control. We were not directly affected by these recent incidents, as we did not have any counterparty credit exposure to the above-mentioned firms. We do not believe that our share price was adversely affected by such incidents since June 30, 2023, but likely was adversely impacted in 2022 and the first half of 2023. The Company has no exposure to any of the cryptocurrency market participants that filed for Chapter 11 bankruptcy or any other counterparties, customers, custodians or other participants in crypto asset markets, or who are known to have experienced excessive redemptions, suspended redemptions, withdrawals of crypto assets or have crypto assets of their customers unaccounted for or material corporate compliance failures; and the Company does not have any assets, material or otherwise, that may not be recovered due to these bankruptcies or excessive or suspended redemptions. However, due to the ongoing instability, volatility and lack of confidence in cryptocurrency mining and markets, the Company found it increasingly difficult to obtain the financing necessary to execute its growth plan. In January 2024, the Company identified the Central Weld Assets as a unique opportunity to add producing oil and gas assets to its asset base and expand its reserves. However, given the increased scrutiny on cryptocurrency activities, the Company was unable to secure a financing source for the NRO Acquisition while retaining the Mining Equipment and operations. Consequently, the Company determined that it was in its best interests to divest its Mining Equipment and focus its attention solely on its oil and gas assets. On January 23, 2024, we closed the Crypto Sale in which we sold all of our Mining Equipment and the Atlas MSA. 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. See “— 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, filed as Exhibit 2.3 to this Annual Report. Master Services Agreement – Atlas On March 2, 2023, the Company entered into the Atlas MSA, pursuant to which Atlas provided the Company with cryptocurrency mining services for the Company’s cryptocurrency miners. In January 2024, pursuant to the Crypto Divestiture Agreement, we assigned, and the Crypto Purchaser assumed, all of the Company’s rights and obligations under the Atlas MSA. Intellectual Property We do not currently own any intellectual property. Employees As of December 31, 2023, we employed 11 full-time employees. We have never experienced a work stoppage, and believe we maintain positive relationships with our employees. Offices As of December 31, 2023, we have leased office space in Houston, Texas, where our principal offices are located, and in Denver, Colorado. 23 Available Information, Website and Availability of Public Filings Our principal executive offices are located at 602 Sawyer Street, Suite 710, 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 on Form 10-K or our other filings with the SEC and is not a part of them. Our common stock is listed and traded on The Nasdaq Stock Market under the symbol “PROP.”