Prairie Operating Co. [PROP] Filings

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2023

For the transition period from ___________ to __________

Commission File Number 001-41895

Prairie Operating Co.
(Exact name of registrant as specified in its charter)

Securities registered pursuant to Section 12(b) of the Exchange Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if a registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on the closing price of the shares of common stock on the OTCQB marketplace on June 30, 2023, was $16,729,050.

The registrant had 10,029,191 shares of common stock outstanding as of March 13, 2024.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders, scheduled to be held on June 5, 2024, are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS

Definitions of Certain Terms and Conventions Used Herein

“Boe/d” means barrel of oil equivalent, using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate, per day.

“developed acres” or “developed acreage” means the number of acres that are allocated or assignable to producing wells or wells capable of production.

“developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.

“development well” means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“exploratory well” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

“gross acres” or “gross wells” means the total acres or wells in which the Company owns a working interest.

“Mbbl” means one thousand barrels of oil.

“Mcf” means one thousand cubic feet.

“MMcf” means one million cubic feet.

“net acres” or “net wells” means the sum of the fractional working interests the Company owns in gross acres or gross wells.

“possible reserves” means 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.

“probable reserves” means those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“productive wells” means a well productive of oil or natural gas.

“proved reserves” means those quantities of oil, natural gas and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or we must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

“proved undeveloped reserves,” “PUD” or “PUD reserves” means proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

“reserves” means estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

“Standardized Measure” means the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.

“undeveloped acres” or “undeveloped acreage” means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

“unproved properties” means properties with no proved reserves.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Annual Report”) contains statements that are forward-looking and as such are not historical facts. These forward-looking statements include, without limitation, statements regarding future financial performance, business strategies, expansion plans, future results of operations, estimated revenues, losses, projected costs, prospects, plans and objectives of management. These forward-looking statements are based on our management’s current expectations, estimates, projections and beliefs, as well as a number of assumptions concerning future events, and are not guarantees of performance. Such statements can be identified by the fact that they do not relate strictly to historical or current facts. When used in this Annual Report, words such as “may,” “should,” “could,” “would,” “expect,” “plan,” “anticipate,” “intend,” “believe,” “estimate,” “continue,” “project” or the negative of such terms or other similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements in this Annual Report include, but are not limited to, statements about:

The forward-looking statements contained in this Annual Report are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements.

These forward-looking statements are not exhaustive. Other sections of this Annual Report include additional factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time, and it is not possible for our management to predict all risk factors nor can we assess the effects of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in, or implied by, any forward-looking statements. Factors that may cause actual results to differ materially from current expectations include, among other things, those listed under Part I, Item 1A. “Risk Factors” and elsewhere in this Annual Report.

Additionally, our discussions of certain environmental, social and governance (“ESG”) matters and issues herein are informed by various standards and frameworks (including standards for the measurement of underlying data), and the interests of various stakeholders. As such, the discussions may not necessarily be “material” under the federal securities laws for Securities and Exchange Commission (“SEC”) reporting purposes. Furthermore, much of this information is subject to methodological considerations or information, including from third parties, that is still evolving and subject to change. For example, our disclosures based on any standards may change due to revisions in framework requirements, availability of information, changes in our business or applicable government policies, or other factors, some of which may be beyond our control.

Our SEC filings are available publicly on the SEC website at www.sec.gov. Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. Accordingly, forward-looking statements in this Annual Report should not be relied upon as representing our views as of any subsequent date, and we undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement.

PART I

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.

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”).

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.

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.”

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:

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.

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:

For more information regarding regulations affecting our permitting, see “Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations.”

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.

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.

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:

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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:

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.

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.

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.”

Item 1A. Risk Factors

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

Risks Related to E&P Assets

The Genesis Assets currently have no producing properties and there is no assurance that we will be able to successfully drill producing wells. If the Genesis Assets are not commercially productive of crude oil or natural gas, any funds spent on exploration and production may be lost.

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

The Central Weld Assets currently have both producing and undeveloped properties and there is no assurance that we will be able to further develop and exploit the producing properties or successfully drill producing wells after closing the NRO Acquisition. If we are unable to further develop and exploit the producing properties or drill producing wells, any funds spent on the NRO Acquisition or in the exploration, development and production of the Central Weld Assets may be lost.

Certain of the Central Weld Assets are producing, permitted properties and certain of the Central Weld Assets are undeveloped. Even if we are able to successfully close the NRO Acquisition, there is no assurance that we will be able to further develop and exploit the producing properties or successfully drill producing wells of the undeveloped properties, and we will be dependent on further developing, exploiting and establishing sufficient reserves at the Central Weld Assets for additional cash flow and a return of our investment. If we are unable to further develop or exploit the Central Weld Assets or if the Central Weld Assets are not economic, all of the funds that we have invested, or will invest, will be lost. In addition, the failure of the Central Weld Assets to further produce commercially may make it more difficult for us to raise additional funds in the form of additional sale of our equity securities or working interests in other property in which we may acquire an interest.

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

All of the reserves attributable to the Genesis Assets are undeveloped and all reserves associated therewith, other than in respect of the Genesis Bolt-on Assets that were acquired in February 2024, are classified as possible reserves. Development of proved undeveloped reserves and possible undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves and those that we may ultimately acquire in the NRO Acquisition, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated PUDs, possible undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our PUDs as unproved reserves.

The Company has no history of drilling producing oil and gas wells and there can be no assurance that we will successfully establish oil and gas operations or profitably produce oil, natural gas or NGLs.

The Company has not successfully drilled a producing oil and gas well nor successfully produced hydrocarbons, and we have no ongoing drilling operations or revenues from drilling operations. Oil and gas exploration and production has a high degree of risk. The future development of a significant portion of our properties will require obtaining permits and financing. As a result, we are subject to all of the risks associated with establishing new drilling operations and business enterprises, including, among others:

There is no assurance that our drilling activities will result in the successful production of oil, natural gas or NGLs. Moreover, there is no assurance that even if we are able to successfully produce oil, natural gas or NGLs that such production would be economical for commercial production. Oil and gas production is dependent upon a number of factors and significantly influenced by the technical skill of our operations personnel involved. The commercial viability of our possible future production is also dependent upon a number of factors which are beyond our control, including the quality of our oil, natural gas and NGLs, commodity prices, government policies and regulation, and environmental protection requirements. There is no certainty that the expenditures that have been made and may be made in the future by the Company related to the acquisition and development of our properties will result in commercially viable production and the Company’s past and future expenditures may be partially or entirely lost.

Since we have no operating history related to the exploration and production of oil and gas assets, investors have no basis to evaluate our ability to operate profitably as an E&P business.

We have not generated any revenue in the exploration and production of oil and gas assets to date which, following the Crypto Sale, is our sole business segment. We face many of the risks commonly encountered by other new businesses, including the lack of an established operating history, need for additional capital and personnel, and competition. There is no assurance that our business will be successful or that we can ever operate profitably. We may not be able to effectively manage the demands required of a new business, such that we may be unable to implement our business plan or achieve profitability.

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

Following the acquisition and development of our existing and future E&P assets, our revenues, profitability and cash flows will depend upon the prices for oil, natural gas and NGLs. The prices we may receive for oil, natural gas and NGLs production are volatile and a decrease in prices can materially and adversely affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms. Changes in oil, natural gas and NGLs prices have a significant impact on the amount of oil, natural gas and NGLs that we can produce economically, the value of our reserves and on our cash flows. Historically, world-wide oil, natural gas and NGLs prices and markets have been subject to significant change and may continue to change in the future. During the year ended December 31, 2023, the average West Texas Intermediate (“WTI”) spot price was $77.58, as compared to an average price of $94.90 for the year ended December 31, 2022 and $68.16 for the year ended December 31, 2021. The average Henry Hub natural gas spot price during the year ended December 31, 2023, was $2.54 as compared to an average of $6.42 for the year ended December 31, 2022 and $3.60 for the year ended December 31, 2021.

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

Our plan to develop and operate our existing and future E&P assets will require substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future.

While we currently expect to develop and operate our existing and future E&P assets utilizing cash flow from operations, we may be unable to do so. Obtaining permits and approvals, seismic data, as well as exploration, development and production activities entail considerable costs, and, to the extent we are unable to fund such costs utilizing cash flow from operations, we may need to raise substantial additional capital, through future private or public equity offerings, strategic alliances or other alternative arrangements.

Our future capital requirements will depend on many factors, including:

If we raise additional capital through equity financing, the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. While we do not intend to finance our operations by relying on debt financing, if we were to raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we are not successful in raising additional capital, we may be unable to continue our future exploration, development and production activities.

We intend to enter into hedging arrangements as we grow our production and therefore we will be exposed to fluctuations in the price of oil, natural gas and NGLs and will be affected by continuing and prolonged declines in such prices. Any future hedging activities we may engage in may result in financial losses or could reduce our income.

Oil, natural gas, and NGL prices are volatile. We intend, in the future, to hedge a significant portion of oil and natural gas production to reduce our exposure to adverse fluctuations in these prices. We are currently not hedged and therefore are exposed to price volatility once we have oil, natural gas and NGL production and may be subject to significant reduction in prices, which would have a material negative impact on our results of operations. In the future, we intend to enter into derivative arrangements for a portion of our oil, natural gas, and NGL production, including swaps, collars and other instruments. Derivative arrangements would expose us to the risk of financial loss in some circumstances, including when: (i) production is less than the volume covered by the derivative instruments; (ii) the counterparty to the derivative instrument defaults on its contract obligations; or (iii) there is an increase in the differential between the underlying price in the derivative instrument and actual prices received. These types of derivative arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements. If oil, natural gas and NGL prices upon settlement of derivative swap contracts exceed the price at which commodities have been hedged, we will be obligated to make cash payments to counterparties, which could, in certain circumstances, be significant.

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

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

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

We intend to pursue the development of our properties in the DJ Basin through horizontal drilling and completion. Horizontal development operations can be more operationally challenging and costly relative to vertical drilling operations.

Horizontal drilling is generally more complex and more expensive on a per well basis than vertical drilling. As a result, there is greater risk associated with a horizontal well program. Risks associated with our horizontal drilling program include, but are not limited to, the following, any of which could materially and adversely impact the success of our horizontal drilling program and, thus, our cash flows and results of operations:

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity, or depressed natural gas and oil prices, the return on our investment in these areas may not be as attractive as anticipated. Further, as a result of any of these developments, we could incur material impairments of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

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

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

Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity.

Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

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

Certain of the undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

The terms of our oil and gas leases often stipulate that the lease will terminate if not held by production, rentals, or otherwise some form of an extension payment to extend the term of the lease. If production in paying quantities is not established on units containing leases during the next year, then approximately 6,598 net acres of our Initial Genesis Assets will expire in 2024, approximately 2,567 net acres of our Initial Genesis Assets will expire in 2025 and approximately 14,320 net acres of our Genesis Assets will expire in 2026 and thereafter. While some expiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. Further, existing leases which are currently held by production may unexpectedly encounter operational, political, regulatory, or litigation challenges which could result in their termination. It is possible that market conditions at the time of negotiation could require us to agree to new leases on less favorable terms to us than the terms of the expired leases or cause us to lose the leases entirely. If our leases expire, we will lose our right to develop the related properties.

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

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find, or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition, and results of operations would be materially and adversely affected.

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

Numerous uncertainties are inherent in estimating quantities of oil, natural gas and NGLs reserves. The process of estimating oil, natural gas and NGLs reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, including assumptions regarding future oil, natural gas and NGLs prices, subsurface characterization, production levels and operating and development costs. Our estimates of possible reserves for the Initial Genesis Assets as of December 31, 2023 were prepared by CG&A. CG&A conducted a detailed review of the Initial Genesis Assets for the period covered by its reserve report using information provided by us.

Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. As a result of the uncertainties, estimated quantities of oil, natural gas and NGLs reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery and estimates of future net cash flows. As of December 31, 2023 all of our reported reserves and associated future cash flows are deemed possible. Estimates of possible reserves, and the future cash flows related to such estimates, are also inherently imprecise and are more uncertain than estimates of proved and probable reserves, respectively, and the respective future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of possible reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved and probable reserves, respectively, and the respective future cash flows related to such estimates, and should not be summed arithmetically with estimates of either proved or probable reserves, respectively, and the respective future cash flows related to such estimates.

When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. 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. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve 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. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and we believe that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

To market our oil and natural gas production, we are dependent upon obtaining access to midstream infrastructure, including truck transportation, pipelines, transmission and/or storage and processing facilities. If we are unable to obtain such access on commercially reasonable terms or at all, we would be unable to market and sell our production and our business and financial position would be materially and adversely affected.

The marketing of oil and natural gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, as well as the existence of adequate markets. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. We rely, and expect to rely in the future, on facilities developed and owned by third parties in order to store, process, transmit and sell our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could materially and adversely affect our ability to produce and market oil and natural gas.

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

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

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

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

We will face strong competition from other oil and gas companies.

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

Government regulation and liability for oil and natural gas operations may adversely affect our business and results of operations.

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

All of our E&P assets are located in the DJ Basin, making us vulnerable to risks associated with operating primarily in a single geographic area.

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

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

Moreover, climate change may result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if facilities are subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may ultimately reduce demand for the products we provide. Such physical risks may also impact our suppliers, which may adversely affect our ability to provide our products. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.

Our operations will be subject to federal, state and local laws and regulations related to environmental and natural resources protection and occupational health and safety, which may expose us to significant costs and liabilities and result in increased costs and additional operating restrictions or delays.

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

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

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

The general trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

Our oil and gas exploration, production, and development activities may be subject to a series of risks related to climate change and energy transition initiatives.

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

Also at the federal level, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, and impose new standards reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. In December 2023 the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rules are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to the EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial.

In addition, the U.S. Congress may continue to consider and pass legislation related to the reduction of GHG emissions, including methane and carbon dioxide. For example, the IRA, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities, was signed into law in August 2022. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA. In January 2024, the EPA issued a proposed rule to implement the waste emissions charge with a proposed effective date in 2025 for reporting year 2024 emissions. The methane charge and the incentives for renewable energy infrastructure development could impose additional costs on our operations and further accelerate the transition of the economy away from the use of oil and natural gas towards lower- or zero-carbon emissions alternatives. Furthermore, on March 6, 2024, the SEC finalized a rule requiring the reporting of climate-related risks and financial impacts, as well as GHG emissions for larger companies. Compliance dates under the final rule are phased in by registrant category. Smaller reporting companies will be required to incorporate climate-related disclosures into their filings beginning in fiscal year 2027. Accelerated filers will be required to incorporate the disclosures in fiscal year 2026, as well as disclosure of Scope 1 and 2 GHG emissions, if material, in fiscal year 2028, and limited assurance attestation reports related to the same by fiscal year 2031. Large accelerated filers will be required to incorporate the disclosures in fiscal year 2025, with Scope 1 and 2 GHG emissions disclosures, if material, in fiscal year 2026, and attestation reports by fiscal year 2029. While we are still assessing our obligations under the rule, complying with such obligations may result in increased costs.

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

At the international level, the United Nations-sponsored Paris Agreement, though non-binding, calls for signatory nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. In February 2021, President Biden recommitted the United States to long-term international goals to reduce emissions, including those under the Paris Agreement. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50 to 52 percent from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community convenes annually at the Conference of the Parties to negotiate further pledges and initiatives, such as the Global Methane Pledge (a collective goal to reduce global methane emissions by 30 percent from 2020 levels by 2030). The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement or other international agreements cannot be predicted at this time. In December 2023, at the 28th Conference of the Parties, the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity, though no timeline for doing so was set. While non-binding, the agreements coming out of these conferences could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for, and increase potential opposition to, the exploration and production of fossil fuels.

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

There are also increasing financial risks for oil and gas producers as certain shareholders, bondholders and lenders may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Certain institutional lenders who provide financing to fossil-fuel energy companies have shifted their investment practices to those that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies in the short or long term. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. Additionally, there is also the possibility that financial institutions will be pressured or required to adopt policies that limit funding for fossil fuel energy companies. For example, in 2021 the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network for Greening the Financial System to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. In September 2022, the Federal Reserve announced that six of the largest U.S. largest banks will participate in a pilot climate scenario analysis exercise, which took place throughout 2023, to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. While we cannot predict what policies may result from these developments, such efforts could make it more difficult to secure funding for exploration and production business activities on favorable terms, or at all. Although there has been recent political support to counteract these initiatives, these and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Any material reduction in the capital available to us or our fossil fuel-related customers could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could reduce the demand for our products and services.

Our oil and gas exploration, production, and development activities may be subject to physical risks related to potential climate change impacts.

Increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, wildfires, and floods and other climatic events, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to cause physical damage to our assets or those of our vendors and suppliers and could disrupt our supply chains, and thus could have an adverse effect on our business, financial position, operations and prospects.

Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or its production. While our operational consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Our business and ability to secure financing may be adversely impacted by increasing stakeholder and market attention to ESG matters.

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

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

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

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

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

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

Additionally, we must dispose of the fluids produced during oil and natural gas production, including produced water. We may choose to dispose of produced water into deep wells by means of injection, either directly ourselves or through third party contractors. While we may seek to reuse or recycle produced water instead of disposing of such water, our costs for disposing of produced water could increase significantly as a result of increased regulation or if reusing and recycling water becomes impractical. Disposal wells are regulated pursuant to the UIC program established under the SDWA and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for construction and operation of such disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed.

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

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

The ESA and comparable state laws protect endangered and threatened species and their habitats. Under the ESA, the U.S. Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of species listed as threatened or endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act of 1918. Such designations could require us to develop mitigation plans to avoid potential adverse effects to protected species and their habitats, and our oil and gas operations may be delayed, restricted or prohibited in certain locations or during certain seasons, such as breeding and nesting seasons, when those operations could have an adverse effect on the species. Moreover, the future listing of previously unprotected species as threatened or endangered in areas where we are operating in the future could cause us to incur increased costs arising from species protection measures or could result in delays, restrictions or prohibitions on our planned development and production activities.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but have not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged with the enactment of the IRA, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Risks Related to the NRO Acquisition

We may not consummate the NRO Acquisition on the terms currently contemplated, or at all.

We expect the NRO Acquisition to close in the first half of 2024, but 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. Certain of the conditions that remain to be satisfied include, but are not limited to:

As a result, the NRO Acquisition may not close as scheduled, or at all. Failure to complete the NRO Acquisition, including as a result of failure to raise sufficient funds, or any delays in completing the NRO Acquisition could have significant adverse impacts on our business, including the following:

If the NRO Acquisition is not completed, the risks described above may materialize and they may have a material adverse effect on our results of operations, cash flows, financial position and stock price.

We do not currently have sufficient funds or committed financing necessary to consummate the NRO Acquisition and the NRO Agreement does not include a financing condition.

Pursuant to the NRO Agreement, we deposited $9.0 million of the Purchase Price (the “Deposit”) into an escrow account on January 11, 2024. Upon closing of the NRO Acquisition, the Deposit will be released to NRO with a corresponding credit to the Purchase Price. In the event the closing has not occurred in accordance with the terms of the NRO Agreement prior to June 17, 2024, and (i) such delay has not occurred as a result of the failure of NRO to materially perform, when required, any of NRO’s covenants or obligations pursuant to the NRO Agreement, (ii) all conditions precedent to the obligations of NRO, as set forth in the NRO Agreement, have been satisfied or have been waived by NRO, and (iii) in our reasonable discretion, there has been no event of Force Majeure or Material Adverse Effect (each as defined below), such that we are, or will be, unable to secure satisfactory financing with respect to the NRO Acquisition, then the Deposit is subject to release to NRO, for so long as such foregoing conditions continue on such dates, in $3,000,000 installments on each of June 17, 2024, July 15, 2024 and August 12, 2024. In the event closing has not occurred prior to August 15, 2024 as a result of the failure by us to materially perform any of our covenants or obligations under the NRO Agreement, NRO shall receive the entirety of the Deposit, which shall be the sole and exclusive remedy available to NRO for any such failure to consummate the closing.

The NRO Agreement contains customary representations, warranties, covenants and agreements. As a condition to closing, we represented that we will have, by the date of the closing, sufficient cash in immediately available funds with which to pay the cash component of the Purchase Price and otherwise will be able to consummate the NRO Acquisition and perform our obligations under the NRO Agreement. We may terminate the NRO Agreement at any time prior to the closing upon the occurrence of an event of Force Majeure or Material Adverse Effect, in each case the result of which that we determine, in our reasonable discretion, that we are, or will be, unable to secure satisfactory financing with respect to the NRO Acquisition.

For an impediment to our ability to secure satisfactory financing with respect to the NRO Acquisition to constitute an event of “Force Majeure,” the impediment must be an unforeseeable circumstance which is beyond the control of us or NRO, or any unavoidable event, even if foreseeable, as a result of which we or NRO are unable to perform our obligations, in whole or in part, under the NRO Agreement. Such circumstances include, but are not limited to: (i) acts of God; (ii) flood, fire, earthquake or explosion; (iii) current or future war, invasion, hostilities (whether war is declared or not), terrorist threats or acts, riots, or other civil unrest; (iv) actions, embargoes, or blockades in effect on or after the date of the NRO Agreement; (v) declared national or regional emergency; or (vi) epidemic, pandemic or other similar outbreak or infection. For such an impediment to constitute a “Material Adverse Effect,” such impediment must be a change, development, or effect (individually or in the aggregate), whether foreseeable or unforeseeable, which, when taken as a whole is, or is reasonably likely to be, materially adverse (a) to the business, assets, value, results of operations or conditions (financial or otherwise) of us or NRO, the Central Weld Assets, or the assets or properties of us or NRO, or (b) to the ability of us or NRO to perform on a timely basis any material obligation under the NRO Agreement or any agreement, instrument or document entered into or delivered in connection therewith. Changes, developments or effects relating to: (x) the economy in general (including any effects on the economy arising as a result of acts of terrorism), (y) changes in commodity prices for hydrocarbons or other changes affecting the U.S. oil and gas industry generally, or (z) the announcement of the NRO Acquisition, shall not be deemed to constitute a Material Adverse Effect and shall not be considered in determining whether a Material Adverse Effect has occurred. Neither any delay in completing the proposed offering of our common stock, nor our inability, in and of itself, to satisfy our obligations to secure financing for the NRO Acquisition, will constitute an event constituting a Material Adverse Effect.

We expect to fund the transaction through a combination of public and/or private issuances of common stock, cash on hand, and proceeds from exercises of currently outstanding warrants. To the extent we are not able to fund the NRO Acquisition on a timely basis, whether due to a failure to successfully complete a public or private equity offering or otherwise, we may be required to seek alternative financing arrangements, and such financing may not be available on favorable terms, or at all, and the NRO Acquisition may be delayed or may not occur. If we are unable to secure financing and an event of Force Majeure or Material Adverse Effect has not occurred, we will be in breach of the NRO Agreement, will not receive the benefits of the Central Weld Assets and the Deposit will be released to NRO.

We may be unsuccessful in integrating the Central Weld Assets or in realizing all or any part of the anticipated benefits of the NRO Acquisition.

We believe that the NRO Acquisition will complement our growth strategy by providing operational and financial scale and increasing free cash flow. However, achieving these goals requires, among other things, realization of the targeted synergies expected from the acquisition, and there can be no assurance that we will be able to successfully integrate the Central Weld Assets or otherwise realize the expected benefits of the NRO Acquisition. This growth and the anticipated benefits of the NRO Acquisition may not be realized fully or at all, or may take longer to realize than expected. Difficulties in integrating the Central Weld Assets may result in the Company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties in realizing the anticipated benefits of the NRO Acquisition includes, but is not limited to, the following:

We have incurred, and expect to continue to incur, a number of costs associated with completing the NRO Acquisition. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the Central Weld Assets, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all.

We cannot assure you that our diligence review of the NRO Acquisition has identified all material risks associated with the transaction. Additionally, following the consummation of the NRO Acquisition, if certain risks arise, the Company may be required to take write-downs or write-offs, restructuring and impairment or other charges that could have a significant negative effect on its financial condition, results of operations and stock price, which could cause you to lose some or all of your investment.

Before entering into the NRO Agreement, we performed a due diligence review of NRO and its business and operations, including an inspection of the Central Weld Assets, which we believe to be generally consistent with industry practices; however, we cannot assure you that our due diligence review identified all material issues and our assessments of the Central Weld Assets and our estimates are inherently uncertain. As a result, we may be forced to later write-down or write-off assets, restructure our operations or incur impairment or other charges that could result in losses. Even if our due diligence successfully identified certain risks, unexpected risks may arise and previously known risks may materialize in a manner not consistent with our preliminary risk analysis. These risks that may not have arisen in the scope of our due diligence review of NRO, include, but are not limited to, title, production, environmental or other problems. Even though these charges may be non-cash items and may not have an immediate impact on our liquidity, the fact that we report charges of this nature could contribute to negative market perceptions about the Company following the completion of the NRO Acquisition or its securities. In addition, charges of this nature may impair our ability to obtain future financing on favorable terms or at all. Moreover, the Company may have limited recourse against NRO for certain risks or liabilities incurred after the consummation of the NRO Acquisition. Accordingly, any of our stockholders who choose to remain stockholders of the Company following the NRO Acquisition could suffer a reduction in the value of their shares. Such stockholders are unlikely to have a remedy for such reduction in value.

We may not achieve the perceived benefits of the Crypto Sale and the NRO Acquisition and the market price of our common stock following these transactions may decline.

The market price of our common stock may decline as a result of the Crypto Sale or the NRO Acquisition for a number of reasons, including if investors react negatively to the prospects of the Company’s business; the effect of the Crypto Sale or the NRO Acquisition on the Company’s business and prospects is not consistent with the expectations of our management or of financial or industry analysts; or the Company does not achieve the perceived benefits of the Crypto Sale or the NRO Acquisition as rapidly or to the extent anticipated by our management or financial or industry analysts.

We expect to incur significant transaction costs in connection with the NRO Acquisition, which may be in excess of those currently anticipated.

We have incurred and are expecting to continue to incur a number of non-recurring costs associated with negotiating and completing the NRO Acquisition, integrating the Central Weld Assets and achieving desired synergies. These costs have been, and will continue to be, substantial and, in many cases, will be borne by us whether or not the NRO Acquisition is consummated. A substantial majority of non-recurring expenses will consist of transaction costs and include, among others, fees paid to financial, legal, accounting and other advisors. We will also incur costs related to formulating and implementing integration plans, including facilities and systems consolidation costs. We will continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in connection with the NRO Acquisition and the integration of the Central Weld Assets. While we have assumed that a certain level of expenses would be incurred, there are many factors beyond our control that could affect the total amount or the timing of the expenses. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the Central Weld Assets, may not offset integration-related costs and achieve a net benefit in the near term, or at all. The costs described above and any unanticipated costs and expenses, many of which will be borne by us even if the NRO Acquisition is not consummated, could have an adverse effect on our financial condition and operating results.

The NRO Acquisition may be completed on different terms from those contained in the NRO Agreement.

Prior to the completion of the NRO Acquisition, we and NRO may, by mutual agreement, amend or alter the terms of the NRO Agreement, including with respect to, among other things, the consideration payable by us to NRO or any covenants and agreements with respect to NRO’s operations during the pendency thereof. Any such amendments or alterations may have negative consequences to us.

The market price for our common stock following the NRO Acquisition, if consummated, may be affected by factors different from those that historically have affected or currently affect our common stock.

If the NRO Acquisition is consummated, our financial position may differ from our financial position before the completion of the NRO Acquisition, and our results of operations may be affected by some factors that are different from those currently affecting our results of operations or those currently affecting the results of operations of NRO. Accordingly, the market price and performance our common stock is likely to be different from the performance of our common stock in the absence of the NRO Acquisition. For a discussion of the business of NRO and important factors to consider in connection with the business, see “Business—NRO Acquisition.”

Securities class action and derivative lawsuits may be brought against us in connection with the NRO Acquisition, which could result in substantial costs.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.

Risks Related to the Company

We have historically incurred significant losses, and may be unable to generate profitability. Our ability to successfully operate and expand our business is dependent on the consummation of the NRO Acquisition or our ability to raise additional capital to support our drilling program on our existing assets.

Historically, we have relied upon cash from financing activities to fund substantially all of the cash requirements of our activities and have incurred significant losses and experienced negative cash flow. For the year ended December 31, 2023, we incurred a net loss of $79.1 million, and for the year ended December 31, 2022, we incurred a net loss of $0.5 million. We had stockholders’ equity of $40.2 million and members’ deficit of $0.4 million as of December 31, 2023 and December 31, 2022, respectively. Furthermore, we sold all of our revenue-generating assets in the Crypto Sale. We do not currently have sufficient capital to consummate the NRO Acquisition or to begin development activities on any of our existing assets. As a result, until we are able to raise additional capital to consummate the NRO Acquisition or enable us to drill wells on our existing properties, we will be unable to generate any revenue. We cannot predict if we will be able to raise the necessary capital and, even if we are able to raise sufficient funds to complete the NRO Acquisition or commence drilling operations and production on our assets, whether such production will be profitable. We may continue to incur losses for an indeterminate period of time and may be unable to sustain profitability. An extended period of losses and negative cash flow may prevent us from successfully operating and expanding our business. We may be unable to sustain or increase our profitability on a quarterly or annual basis. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

We will require significant additional capital to fund our growing operations; we may not be able to obtain sufficient capital and may be forced to limit the scope of our operations.

We may not have sufficient capital to fund our future operations without significant additional capital investments, including the planned drilling of oil and gas wells. If adequate additional financing is not available on reasonable terms or at all, we may not be able to carry out our corporate strategy and we would be forced to modify our business plans (e.g., limit our growth, and/or decrease or eliminate capital expenditures), any of which may adversely affect our financial condition, results of operations and cash flow. Such reduction could materially adversely affect our business and our ability to compete. There can be no assurance that financing will be available in a timely manner or in amounts or on terms acceptable to the Company, or at all.

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

We may not be able to obtain additional financing on terms favorable to us, if at all. If we are unable to obtain adequate financing or financing on terms satisfactory to us when we require it, our ability to continue to support our business growth and respond to business challenges could be significantly impaired, and our business may be adversely affected. Our capital needs will depend on numerous factors, including, without limitation, our profitability, and the amount of our capital expenditures, including acquisitions. Moreover, the costs involved may exceed those originally contemplated. Failure to obtain intended economic benefits could adversely affect our business, financial condition and operating performances.

We need to manage growth in operations to maximize our potential growth and achieve our expected revenues. Our failure to manage growth can cause a disruption of our operations that may result in the failure to generate revenues at levels we expect.

In order to maximize potential growth, we may have to expand our operations. Such expansion will place a significant strain on our management and our operations. Our failure to manage our growth could disrupt our operations and ultimately prevent us from generating the revenues we expect.

We depend on the services of a small number of key personnel, and may not be able to operate and grow our business effectively if we lose their services or are unable to attract qualified personnel in the future.

Our success depends in part upon the continued service of a small number of key personnel. They are critical to the overall management of the Company, and our strategic direction. We rely heavily on them because they have substantial experience with the Company and our business strategies. Our ability to retain them is therefore very important to our future success. We have employment agreements with our key personnel, but these employment agreements do not ensure that they will not voluntarily terminate their employment with us. The loss of any key personnel would require the remaining key personnel to divert immediate attention to seeking a replacement. Competition for senior management personnel is intense, and our inability to find a suitable replacement for any departing key personnel in a timely basis could adversely affect our ability to operate and grow our business.

Past performance by members of the Company’s management team may not be indicative of an ability to complete the NRO Acquisition or of future performance of the Company.

Past performance and operational experience of our management team and their affiliates is not a guarantee of the Company’s ability to complete the NRO Acquisition nor, if consummated, a guarantee that the intended benefits of the NRO Acquisition will be achieved or that we will be able to successfully develop and operate the Genesis Assets. You should not rely on the historical record of our management team or their affiliates’ performance as indicative of the future performance of the Company or of an investment in our common stock.

We will rely on key contracts and business relationships, and if our current or future business partners or contracting counterparties fail to perform or terminate any of their contractual arrangements with us for any reason or cease operations, or should we fail to adequately identify key business relationships, our business could be disrupted and our reputation may be harmed.

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

Terrorist attacks, cyberattacks and threats could have a material adverse effect on our business, financial condition and results of operations.

Terrorist attacks or cyberattacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Cyber incidents, including deliberate attacks, have increased in frequency globally. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the United States. We depend on digital technology in many areas of our business and operations, including recording financial and operating data, oversight and analysis of our operations and communications with the employees supporting our operations and our customers or service providers. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. The secure processing, maintenance and transmission of information is critical to our operations, and we monitor our key information technology systems in an effort to detect and prevent cyberattacks, security breaches or unauthorized access. Despite our security measures, our information technology systems may undergo cyberattacks or security breaches including as a result of employee error, malfeasance or other threat vectors, which could lead to the corruption, loss, or disclosure of proprietary and sensitive data, misdirected wire transfers, and an inability to: perform services for our customers; complete or settle transactions; maintain our books and records; prevent environmental damage; and maintain communications or operations. Significant liability to the Company or third parties may result. We are not able to anticipate, detect or prevent all cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until an attack is already underway or significantly thereafter, and because attackers are increasingly using technologies specifically designed to circumvent cybersecurity measures and avoid detection. Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.

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

The terms of indebtedness we may incur in the future, including our anticipated revolving credit facility, may restrict our future business and operations.

While we currently do not have any long-term debt obligations and our goal is to operate with limited leverage, we intend to enter into a revolving credit facility primarily to support our hedging activities in connection with the consummation of the NRO Acquisition, and may incur other indebtedness in the future. The revolving credit facility may contain covenants limiting our ability to pay dividends, incur indebtedness, grant liens, make acquisitions, make investments or dispositions, engage in transactions with affiliates and enter into hedging and derivative arrangements, as well as covenants requiring us to maintain certain financial ratios and tests. In addition, the borrowing base under a credit facility may be subject to periodic review by our lenders. Difficulties in the credit markets may cause the banks to be more restrictive when redetermining the borrowing base. We can make no assurances that we will be able to enter into a credit facility.

Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and borrowings or equity financing may not be available to pay or refinance such debt. If we are unable to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our debt on commercially reasonable terms, our business and financial condition could materially and adversely be affected.

Acquisitions, joint ventures or similar strategic relationships may disrupt or otherwise have a material adverse effect on our business and financial results.

As part of our strategy, we may explore strategic acquisitions and combinations, or enter into joint ventures or similar strategic relationships. These transactions are subject to the following risks:

Acquisitions may result in significant impairment charges and may operate at losses. We can provide no assurance that future acquisitions, joint ventures or strategic relationships will be accretive to our business overall or will result in profitable operations.

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.

On January 23, 2024, pursuant to the Crypto Divestiture Agreement, we sold all of our Mining Equipment and related assets for total consideration of $2 million, including $1 million in cash and $1 million in deferred cash payments, to be paid out of (i) 20% of the net monthly 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 (ii) thereafter, 50% of the net monthly revenues received by the Crypto Purchaser associated with or otherwise attributable to the Mining Equipment until the aggregate amount of such payments equals $1 million, plus accrued interest. In addition to the Mining Equipment, we assigned all our rights and obligations under the Atlas MSA to the Crypto Purchaser.

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. Our receipt of the Deferred Purchase Price is subject to numerous risks outside of our control, including:

While we no longer have direct exposure to the fluctuation and volatility of Bitcoin prices, we will remain indirectly exposed to such volatility until the Deferred Purchase Price has been paid in full. If the market price of Bitcoin decreases to the point where the Crypto Purchaser does not find it economically feasible to operate the Mining Equipment or if Atlas suspends operations of the Mining Equipment under the terms of the Atlas MSA, the payment, if any, of the Deferred Purchase Price may be delayed. Although the Crypto Divestiture Agreement requires the Crypto Purchaser to operate the Mining Equipment in the ordinary course of business until the Deferred Purchase Price is paid in full, delays in payment or failure to pay the Deferred Purchase Price due to the economic feasibility of mining Bitcoin or malfeasance of a third party may result in costly litigation. In addition, while we have a security interest in the Mining Equipment as collateral security for the prompt and complete payment and performance in full of the Crypto Purchaser’s obligations under the Crypto Divestiture Agreement, there can be no assurances that the remedies available to us in respect of such security interest will be sufficient. These risks and uncertainties may have a material adverse effect on our cash flows, business, results of operations and financial condition.

Our Charter provides for indemnification of officers and directors at our expense and limits their liability, which may result in a major cost to us and harm the interests of our stockholders because corporate resources may be expended for the benefit of officers and/or directors.

Our Charter and applicable Delaware law provide for the indemnification of our directors and officers against attorney’s fees and other expenses incurred by them in any action to which they become a party arising from their association with or activities on our behalf. This indemnification policy could result in substantial expenditures by us that we will be unable to recoup.

We have been advised that, in the opinion of the SEC, indemnification for liabilities arising under federal securities laws is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification for liabilities arising under federal securities laws, other than the payment by us of expenses incurred or paid by a director, officer or controlling person in the successful defense of any action, suit or proceeding, is asserted by a director, officer or controlling person in connection with the securities being registered, we will (unless in the opinion of our counsel, the matter has been settled by controlling precedent) submit to a court of appropriate jurisdiction, the question whether indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. The legal process relating to this matter, if it were to occur, is likely to be very costly and may result in us receiving negative publicity, either of which factors is likely to materially reduce the market and price for our shares if such a market ever develops.

There may be conflicts of interest between certain of our officers and directors and our non-management stockholders.

Conflicts of interest create the risk that management may have an incentive to act adversely to the interests of other stockholders. A conflict of interest may arise between our officers and directors’ personal pecuniary interests and their fiduciary duty to our stockholders. Furthermore, our officers and directors’ own pecuniary interests may not align with their fiduciary duties to our stockholders. Edward Kovalik (Chief Executive Officer and Chairman of the Board), Gary C. Hanna (President and Director) and Paul Kessler (Director) have certain overriding royalty interests in the Initial Genesis Assets. To avoid any potential conflict of interest with certain members of the Board and management owning certain overriding royalty interests under the Initial Genesis Assets, all of the Company’s drilling programs will be approved by an independent committee of the Board on a quarterly basis.

Future litigation or governmental proceedings could result in material adverse consequences, including judgments or settlements.

From time to time, we may be involved in lawsuits, regulatory inquiries, governmental and other legal proceedings, such as title, royalty or contractual disputes, our oil and gas development activities, environmental liabilities, regulatory compliance matters, personal injury, property damage and employment litigation, in the ordinary course of our business. Many of these matters raise difficult and complicated factual and legal issues and are subject to uncertainties and complexities. The timing of the final resolutions to these types of matters is often uncertain. Additionally, the possible outcomes or resolutions to these matters could include adverse judgments or settlements, either of which could require substantial payments, adversely affecting our results of operations and liquidity. Irrespective of the outcome, legal proceedings or governmental investigations may adversely affect our business due to legal costs, diversion of resources and the attention of our management and employees, and other factors.

Due to the recent listing of our common stock on Nasdaq, we will incur materially increased costs and become subject to additional regulations and requirements.

Due to the recent listing of our common stock on Nasdaq, we will incur material legal, accounting and other expenses, including payment of annual exchange fees, to satisfy the continued listing standards for Nasdaq. In connection with the listing of our common stock on Nasdaq, we now must meet certain financial and liquidity criteria to maintain our listing, as well as standards of Board independence, committee composition and governance and Board diversity, only some of which criteria and standards include time periods to comply after listing. If we fail to meet any of Nasdaq’s listing standards, our common stock may be delisted. In addition, our Board may determine that the cost of maintaining our listing on a national securities exchange outweighs the benefits of such listing. A delisting of our common stock from Nasdaq may materially impair our stockholders’ ability to buy and sell our common stock and could have an adverse effect on the market price of, and the efficiency of the trading market for, our common stock. The delisting of our common stock could significantly impair our ability to raise capital and the value of your investment.

Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act of 2002 could result in a restatement of our financial statements, cause investors to lose confidence in our financial statements and our Company and have a material adverse effect on our business and stock price.

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

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

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

Furthermore, we must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our annual reports on Form 10-K, including the requirement to have our independent registered public accounting firm attest to the effectiveness of our internal controls, unless we continue to be exempt from such requirement. Our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

We are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make our common stock less attractive to investors.

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

We have utilized these exemptions and expect to continue to utilize these exemptions while we remain a smaller reporting company and non-accelerated filer. These exemptions and reduced disclosures in our SEC filings due to our status as a smaller reporting company mean our auditors do not review our internal control over financial reporting and may make it harder for investors to analyze our results of operations and financial prospects. We cannot predict if investors will find our common stock less attractive because we may rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our common stock prices may be more volatile.

Our Charter and Bylaws designate the state and federal courts located within the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our Charter and Bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery of the State of Delaware does not have jurisdiction, the Superior Court of the State of Delaware, or, if the Superior Court of the State of Delaware does not have jurisdiction, the United States District Court for the District of Delaware) will be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, other employee or agent or stockholder of the Company to the Company or the Company’s stockholders, (iii) any action against the Company arising pursuant to any provision of the DGCL or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware, or (iv) any action against the Company or any director, officer, other employee or agent of the Company asserting a claim governed by the internal affairs doctrine, including, without limitation, any action to interpret, apply, enforce or determine the validity of the Charter or the Bylaws, in each such case subject to such court’s having personal jurisdiction over the indispensable parties named as defendants therein. Our Charter and Bylaws further provide that, unless we consent in writing to the selection of an alternative forum, the federal district courts of the United States of America will be the sole and exclusive forum for the resolution of any complaint asserting a cause of action under the Securities Act. Our Charter and Bylaws provisions do not apply to complaints asserting a cause of action under the Exchange Act. A stockholder may not waive compliance with the federal securities laws and the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of the provisions of our Charter and Bylaws described in the preceding sentences. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Charter and Bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our cash flows.

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

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

Risks Related to Ownership of our Common Stock

The conversion or exercise, as applicable, of the outstanding Series D Preferred Stock, Series E Preferred Stock, Series D PIPE Warrants, Series E PIPE Warrants, Non-Compensatory Options and Exok Warrants could substantially dilute your investment and adversely affect the market price of our common stock.

As of March 13, 2024, the Series D Preferred Stock are convertible into an aggregate of 4,115,426 shares of common stock and the Series D PIPE Warrants are exercisable for an aggregate of 4,613,028 shares of common stock. The Series E Preferred Stock are convertible into an aggregate of 4,000,000 shares of common stock and the Series E PIPE Warrants are exercisable for an aggregate of 8,000,000 shares of common stock. The Exok Warrants are exercisable for an aggregate of 670,499 shares of common stock. In addition, there are outstanding Non-Compensatory Options to purchase an aggregate of 8,000,000 shares of common stock for $7.14 per share which are only exercisable if specific production hurdles are achieved, pursuant to amended and restated non-compensatory Option Agreements entered into at the Merger Effective Time.

In addition, sales of a substantial number of shares of common stock issued upon the conversion or exercise, as applicable, of the outstanding Series E Preferred Stock, Series E PIPE Warrants, Exok Warrants, Series D Preferred Stock, Series D PIPE Warrants, Non-Compensatory Options, or even the perception that such sales could occur, could adversely affect the market price of our common stock. The conversion or exercise of such securities could result in dilution in the interests of our other stockholders and adversely affect the market price of our common stock. For example, as a result of the Warrant Exercise, the Company issued an additional 2,000,000 shares of common stock to the O’Neill Trust, resulting in immediate dilution to existing stockholders of approximately 20%.

Our Board has broad discretion to issue additional securities, and in order to raise sufficient funds to expand our operations, we may have to issue securities at prices which may result in substantial dilution to our stockholders.

We are entitled under our Charter to issue up to 500,000,000 shares of common stock and 50,000,000 shares of preferred stock, although these amounts may change in the future subject to stockholder approval. Shares of our preferred stock provide our Board broad authority to determine voting, dividend, conversion and other rights. Any additional stock issuances could be made at a price that reflects a discount or premium to the then-current market price of our common stock. In addition, in order to raise capital, we may need to issue securities that are convertible into or exchangeable for a significant amount of our common stock. Our Board may generally issue those shares of common stock and preferred stock, or convertible securities to purchase those shares, without further approval by our stockholders. Any preferred stock we may issue could have such rights, preferences, privileges and restrictions as may be designated from time-to-time by our Board, including preferential dividend rights, voting rights, conversion rights, redemption rights and liquidation provisions. We may also issue additional securities to our directors, officers, employees and consultants as compensatory grants in connection with their services, both in the form of stand-alone grants or under our stock incentive plans. The issuance of additional securities may cause substantial dilution to our stockholders.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Insiders have substantial control over the Company, and they could delay or prevent a change in our corporate control even if our other stockholders want it to occur.

As of March 13, 2024, our executive officers and directors, collectively beneficially own approximately 40.51% of our outstanding shares of common stock and the O’Neill Trust beneficially owns 25% of our outstanding shares of common stock. These stockholders are able to exercise significant control over all matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions. This could delay or prevent an outside party from acquiring or merging with our Company even if our other stockholders want it to occur. This may also limit your ability to influence the Company in other ways. In addition, certain investors own significant numbers of convertible securities, that if exercised or converted, could result in ownership of a significant portion of the outstanding shares of common stock of the Company. For example, assuming full exercise or conversion, as applicable, of their respective convertible securities and no exercise or conversion by other security holders, certain holders could acquire a controlling position in the Company’s common stock. The exercise or conversion, as applicable, of the Series D Preferred Stock, Series D PIPE Warrants, Series E Preferred Stock and Series E PIPE Warrants are subject to a beneficial ownership limitation of 4.99% of the outstanding shares of common stock, which may be increased by the holder upon written notice to the Company, to any specified percentage not in excess of 9.99%. The 9.99% beneficial ownership limitation may only be modified, amended or waived with the written consent of both the Company and the security holder. In November 2023, the O’Neill Trust entered into an agreement with 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 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 on the Series D Preferred Stock and Series E Preferred Stock remains at 4.99%, subject to increase to 9.99% by O’Neill Trust upon written notice to the Company. If such beneficial ownership limitation were to be amended or waived for the O’Neill Trust or other holders, certain holders would be able to convert their preferred shares or warrants for a significant portion of the outstanding shares of common stock of the Company, and such holders would be able to exercise significant control over all matters requiring stockholder approval. See Exhibit 4.5 filed with this Annual Report for more information.

The trading price of our common stock has been, and is likely to continue to be, volatile and could be subject to wide fluctuations in response to various factors, some of which are beyond our control.

The market price of our common stock has historically varied greatly, and is likely to continue to be volatile because of numerous factors, including:

Furthermore, from time to time, the stock markets have experienced extreme price and volume fluctuations that have affected and continue to affect the market prices of equity securities of many companies. These fluctuations often have been unrelated or disproportionate to the operating performance of those companies.

These broad market and industry fluctuations, as well as general economic, political and market conditions, such as recessions, interest rate changes, international currency fluctuations or political unrest, may negatively impact the market price of our common stock. In the past, companies that have experienced volatility in the market price of their stock have been subject to securities class action litigation. Any future securities litigation against us could result in substantial costs and divert our management’s attention and resources, and harm our business, financial condition, and results of operations.

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of such shares, or the perception that such sales may occur, could impair our ability to raise capital through the sale of additional common stock or preferred stock.

We have not paid cash dividends in the past and do not expect to pay cash dividends in the foreseeable future. Any return on your investment may be limited to increases in the market price of our common stock.

We have not paid any cash dividends on our common stock to date. We may retain future earnings, if any, for future operations, expansion and debt repayment and have no current plans to pay cash dividends for the foreseeable future. Any decision to declare and pay dividends in the future will be made at the discretion of the Board and will depend on, among other things, our results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board may deem relevant. In addition, our ability to pay dividends may be limited by covenants of any existing and future outstanding indebtedness we or our subsidiaries incur.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 1C. Cybersecurity

Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks

In the normal course of business, we may collect and store certain sensitive Company information, including proprietary and confidential business information, trade secrets, intellectual property, sensitive third-party information and employee information. We seek to assess, identify and manage cybersecurity risks through the processes described below:

We engage third-party service providers as part of our cybersecurity program. For example, we have engaged an independent cybersecurity advisor to review, assess, and make recommendations regarding our information security program and information technology strategic plan. We recognize that third-party service providers introduce cybersecurity risks. In an effort to mitigate these risks, we assess third party cybersecurity controls through the review of systems and organizational controls audit reports performed by independent auditors of certain of our information system related third-party service providers.

The above cybersecurity risk management processes are integrated into the Company’s overall enterprise risk management program. Cybersecurity risks are understood to be significant business risks.

Impact of Risks from Cybersecurity Threats

As of the date of this Annual Report, though the Company and our service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect the Company. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our information technology systems could have significant consequences to the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. See “Risk Factors - Terrorist attacks, cyberattacks and threats could have a material adverse effect on our business, financial condition and results of operations.” for additional information about the risks to our business associated with a breach or compromise to our information technology systems.

Board of Directors’ Oversight and Management’s Role

Our Board is ultimately responsible for overseeing cybersecurity, information security, and information technology risks, as well as management’s actions to identify, assess, mitigate, and remediate those risks. As part of its program of regular risk oversight, the Audit Committee assists the Board in exercising oversight of the Company’s cybersecurity, information security, and information technology risks. On an annual basis, the Audit Committee reviews and discusses with management the Company’s policies, procedures and practices with respect to cybersecurity, information security and information and operational technology, including related risks. In addition, our Chief Financial Officer regularly briefs senior management, the Board of Directors and the Audit Committee on cybersecurity issues as part of our overall enterprise risk management program, which may include information regarding our exposure to privacy and cybersecurity risks deemed to have a moderate or higher business impact, even if immaterial to us.

The Company has an internal management team that focuses on current and emerging cybersecurity matters. The Company’s internal management team is led by the Chief Financial Officer. The internal management team is responsible for implementing cybersecurity policies, programs, procedures, and strategies. Our internal management team includes professionals with backgrounds in information security, risk management, and incident response. Our Chief Financial Officer has experience leading the information technology departments at another publicly-traded, upstream energy company for over four years and led enterprise risk management processes at publicly traded, upstream energy companies for approximately 10 years.

Item 2. Properties

The information required by Item 2. is contained in Item 1. Business and is incorporated herein by reference.

Item 3. Legal Proceedings

The Company is not involved in any disputes and does not have any litigation matters pending which the Company believes could have a materially adverse effect on the Company’s financial condition or results of operations. There is no action, suit, proceeding, inquiry or investigation before or by any court, public board, government agency, self-regulatory organization or body pending or, to the knowledge of the executive officers of our Company or any of our subsidiaries, threatened against or affecting our Company, our common stock, any of our subsidiaries or of our Company’s or our Company’s subsidiaries’ officers or directors in their capacities as such, in which an adverse decision could have a material adverse effect.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for Registrant’s Common Equity. Our common stock is quoted on the Nasdaq under the symbol “PROP.”

Holders. As of March 13, 2024, there were approximately 86 record holders of our common stock. Because brokers and other institutions hold shares on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders.

Dividends. We have not paid any cash dividends on our common stock to date. We may retain future earnings, if any, for future operations, expansion and debt repayment and have no current plans to pay cash dividends for the foreseeable future. Any decision to declare and pay dividends in the future will be made at the discretion of the Board and will depend on, among other things, our results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board may deem relevant. In addition, our ability to pay dividends may be limited by covenants of any existing and future outstanding indebtedness we or our subsidiaries incur. We do not anticipate declaring any cash dividends to holders of the common stock in the foreseeable future.

Recent Sales of Unregistered Securities.

None.

Repurchases.

None.

Item 6 [Reserved]

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis of our financial condition and results of operations for the fiscal years ended December 31, 2023 and 2022 together with our consolidated financial statements and related notes and other financial information appearing in this Annual Report. The discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those described under the headings “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” appearing elsewhere in the Annual Report.

Overview

We are an independent oil and gas company focused on the acquisition and development of crude oil, natural gas and NGLs. We currently hold attractive acreage in 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 E&P assets were acquired in the Exok Transaction (as described 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 offsetting our existing assets. We refer to the assets acquired in these transactions as our “Genesis Assets.” In all, the total Genesis Assets 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 to acquire producing acreage and PUDs that are complementary to our existing acreage, which we refer to as the “Central Weld Assets.” 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. In 2023, we also engaged in cryptocurrency mining operations and these operations accounted for all of our revenues in 2023. In January 2024, we divested all of our cryptocurrency mining assets. See “Business—Recent Developments” for more information regarding the NRO and Genesis Bolt-On Assets acquisitions, as well as the sale of our Cryptocurrency mining operations.

Background

The Merger, Exok Transaction and Related Events

On May 3, 2023, the Company completed the Merger, pursuant to which, among other things, Merger Sub merged with and into Prairie LLC, with Prairie LLC surviving and continuing to exist as a Delaware limited liability company and a wholly owned subsidiary of the Company. Upon consummation of the Merger, the Company changed its name from “Creek Road Miners, Inc.” to “Prairie Operating Co.” 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 this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” or the accompanying financial statements.

In connection with the Merger, we acquired oil and gas leases covering approximately 3,158 net mineral acres in, on and under 4,494 gross acres from Exok for $3.0 million. 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”) 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”).

On August 15, 2023, the Company exercised its option under the Exok Transaction to purchase approximately 20,328 net mineral acres in, on and under approximately 32,695 additional gross acres from Exok (the “Exok Option Assets”). The Company acquired this acreage for $25.3 million consisting of (i) $18.0 million in cash (the “Cash Consideration”) to Exok, (ii) issuance of 670,499 shares of the Company’s common stock and warrants to purchase 670,499 shares of common stock (“Exok Warrants”) to affiliates of Exok, and (iii) direct transaction costs. The Cash Consideration was funded from the Series E preferred issuance (see below).

The Company received an aggregate of $20.0 million in proceeds from the Series E private placement (the “Series E PIPE”) in exchange for 20,000 shares of Series E preferred stock, par value $0.01 per share (“Series E Preferred Stock”) along with 39,614 shares of the Company’s common stock, and Series A warrants to purchase 4,000,000 shares of the Company’s common stock (the “Series E A Warrants”) and Series B warrants to purchase 4,000,000 shares of common stock (the “Series E B Warrants” and together with the Series E A Warrants, the “Series E PIPE Warrants”).

See “Business—Background” for more information regarding the Merger, the Exok Transaction and related events in 2023.

Reverse Stock Split

On October 16, 2023, the Company effected the Reverse Stock Split at an exchange ratio of 1:28.5714286. Unless otherwise noted, all per share and share amounts presented herein have been retroactively adjusted for the effect of the Reverse Stock Split.

Cryptocurrency Mining Operations and Sale

For the year ended December 31, 2023, we generated all of our revenue through our cryptocurrency mining activities. During 2023, our cryptocurrency mining activities consisted of engaging Atlas Power Hosting, LLC (“Atlas”) to operate our cryptocurrency mining assets, some of which were owned by Creek Road prior to the Merger and others that we acquired following the Merger. Pursuant to the Atlas MSA, we did not own, control or take custody of Bitcoin during 2023; rather, Atlas retained all Bitcoin rewards and remitted net revenue from cryptocurrency mining to us in the form of US dollars pursuant to the Atlas MSA. Since the Merger was accounted for as a reverse asset acquisition, 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 this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” or the accompanying financial statements.

On January 23, 2024, we completed the Crypto Sale, pursuant to which we sold all of our cryptocurrency assets and assigned our interests under the Atlas MSA to the Crypto Purchaser. Accordingly, we do not expect to engage in cryptocurrency mining activities in 2024 or thereafter. This disposition did not meet the requirements of held for sale classification at December 31, 2023, but will require presentation as discontinued operations in prospective financial statements. We expect to recognize a loss of $1.1 million in conjunction with this disposition. See “Business—Sale of Crypto Assets” for more information about the sale of our cryptocurrency assets and assignment of the Atlas MSA.

NRO Acquisition

On January 11, 2024, we entered into the NRO Agreement, to acquire the Central Weld Assets for total consideration of $94.5 million, subject to certain closing price adjustments and other customary closing conditions. 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, 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. See “Business—Recent Developments—NRO Acquisition” for a description of the NRO Agreement. We expect 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.”