What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2025-03-06 compared with 2024-03-19 · 688 added, 722 removed, 485 unchanged (74% of the section changed)

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;

(the “Company,” “we,” “our” or “us”) is an independent oil and natural gas company focused on the acquisition and development

of crude oil, natural gas, and NGLs.

Our assets and operations are strategically located in the

oil region of rural Weld County, within the Denver-Julesburg Basin in Colorado (the “DJ Basin” ).

We believe the

DJ Basin to be one of the premier resource plays in the United States (“U.S.”).

Weld County boasts some of the lowest

break-even prices in the U.S., and has a long production history that has proven and consistent results.

The productivity of this

resource is demonstrated by the integral role that Weld County holds in Colorado’s energy economy, having produced 82% of

Colorado’s oil production as of December 2024.

We seek to deliver energy in an environmentally efficient manner by deploying

next-generation technology and techniques.

In addition to growing production through our drilling operations, we also seek to grow our

business through accretive acquisitions focusing on assets with

the following criteria:

(i) producing reserves, with opportunities to add accretive, undeveloped bolt-on acreage;

(ii) ample, high rate-of-return

inventory of drilling locations that can be developed with cash flow reinvestment;

(iii) strong well-level economics;

(iv) liquids-rich assets;

(iv) liquids-rich

and (v) accretive valuation.

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.

“— Recent Developments ” for more information.

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”).

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.

of December 31, 2024, our exploration and production (“E&P”) assets consist of our Central Weld Assets (as defined herein), Genesis and

Genesis Bolt–on Assets (as defined herein), and the Exok Option Purchase (as defined herein) assets.

Our Central Weld Assets

were acquired from Nickel Road Development LLC and Nickel Road Operating LLC (collectively, “NRO”) in October 2024 and

include 26 revenue producing oil and natural gas wells.

of December 31, 2024, our total Genesis Assets include approximately 18,100 net leasehold acres in, on and under approximately 31,000

gross acres and our Central Weld Assets include approximately 5,640 net leasehold acres, on and under approximately 6,000 gross acres.

We commenced drilling wells on our Genesis Bolt-on Assets in the third quarter of 2024 and all eight wells began producing in February

we focused on cryptocurrency mining until the sale of our cryptocurrency miners in January 2024.

Our cryptocurrency mining

operations commenced on May 3, 2023 concurrent with the Merger (as defined herein).

Prior to January 2024, all of our revenue was

generated through our cryptocurrency mining activities from assets that were acquired in the Merger.

Upon the closing of the Crypto

Sale (as defined herein), we exited the cryptocurrency mining business.

Refer to Recent Developments below for

more information.

May 3, 2023, we completed our merger with Prairie Operating Co., LLC, a Delaware limited liability company (“Prairie LLC”),

pursuant to the terms of the Amended and Restated Agreement and Plan of Merger, dated as of May 3, 2023 (the “Merger Agreement”), by and among the Company, Creek Road Merger Sub, LLC (“Merger Sub”),

and Prairie LLC, pursuant to which, among other things, Merger Sub merged with and into Prairie LLC, with Prairie LLC surviving and continuing

to exist as a Delaware limited liability company and a wholly-owned subsidiary of the Company (the “Merger”).

Upon the Merger,

membership interests in Prairie LLC were converted into the right to receive each member’s pro rata share of 2,297,668 shares of

common stock, par value $0.01 per share, of the Company (“Common Stock”).

consummation of the Merger, we changed our name from “Creek Road Miners, Inc.” to “Prairie Operating Co.” We

traded under our former name and ticker symbol “CRKR” until October 16, 2023.

From October 16, 2023 to November 12, 2023,

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.

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):

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;

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;

accrued fees payable to our board of directors (the “Board”) in the amount of $110,250 were converted into shares of common

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;

all amounts payable pursuant to certain convertible promissory notes were converted into shares of common stock.

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.

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.

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.

addition, in connection with the Closing, the Company consummated the purchase of oil and gas leases from Exok, Inc.

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”).

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”).

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.

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

Exok Option Purchase and the Series E PIPE closed on August 15, 2023.

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.

October 13, 2023, the holders of the AR Debentures elected to convert their AR Debentures into an aggregate of 400,666 shares of common

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.

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.

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

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.

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

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.

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.

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.

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.

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.

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.

we expect to close the NRO Acquisition in the first half of 2024, such acquisition is subject to a number of closing conditions.

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.

we traded under symbol “CRKRD,” a transitionary ticker symbol.

We began trading under our current ticker symbol, “PROP,”

on November 13, 2023.

On December 21, 2023, we received approval to list our common stock on the Nasdaq Capital Market (“Nasdaq”).

Trading of our shares of common stock on Nasdaq under the ticker symbol “PROP” commenced at the opening

of trading on December 28, 2023.

October 16, 2023, we effected a reverse stock split at an exchange ratio of 1:28.5714286.

Unless otherwise noted, all per share and share

amounts presented herein have been retroactively adjusted for the effect of the reverse stock split for all periods presented.

February 6, 2025, we and certain of our subsidiaries entered into a Purchase and Sale Agreement (the “Bayswater PSA”) with

Bayswater Resources, LLC, Bayswater Fund III-A, LLC, Bayswater Fund III-B, LLC, Bayswater Fund IV-A, LP, Bayswater Fund IV-B, LP, Bayswater

Fund IV-Annex, LP, and Bayswater Exploration & Production, LLC (collectively, “Bayswater”), pursuant to which we agreed

to acquire the Bayswater Assets from Bayswater for a purchase price of $602.8 million, subject to certain closing price adjustments (all together, the “Bayswater

Acquisition”).

The Bayswater Acquisition has an outside closing date of March 15, 2025,

subject to customary closing conditions, with an economic effective date of December 1, 2024.

However, there can be no assurance that a closing will occur.

Bayswater PSA contains customary representations, warranties and covenants of us and Bayswater for a transaction

of this nature.

January 11, 2024, we entered into an asset purchase agreement (the “NRO Agreement”), by and among the Company, Prairie

LLC and NRO, to acquire the assets of NRO (the

“Central Weld Assets”) for total consideration of $94.5 million (the “Purchase Price”), subject to certain

closing price adjustments and other customary closing conditions (the “NRO Acquisition”).

The Purchase Price consists of

$83.0 million in cash and $11.5 million in deferred cash payments.

The Company deposited $9 million of the Purchase Price into an

escrow account on January 11, 2024 (the “Deposit”).

August 15, 2024, we and NRO agreed to amend certain terms of the NRO Agreement, pursuant to which the total consideration of the NRO

Acquisition was reduced to $84.5 million in cash, subject to certain closing price adjustments and other customary closing

conditions, and the parties agreed to remove the deferred cash payments.

Additionally on August 15, 2024, $6.0 million of the

Deposit was released to NRO and the remaining $3.0 million was returned to us.

October 1, 2024, we closed the NRO Acquisition and paid $49.6 million to the sellers in cash, using cash on hand, the proceeds from

the issuance of Common Stock, and a portion of the proceeds from the issuance of the Senior Convertible Note (as defined herein).

completed the final settlement with NRO in December 2024, which resulted in a final purchase price of $55.5 million.

of Crypto Assets

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”).

January 23, 2024, pursuant to an asset purchase agreement (the “Crypto Divestiture Agreement”) between us and a private

purchaser (the “Crypto Purchaser”), we sold all of our cryptocurrency miners (the “Mining Equipment”) for consideration

consisting of (i) $1.0 million in cash and (ii) $1.0 million in deferred cash payments (the “Deferred Purchase Price”), to

be paid out of (a) 20% of the monthly net revenues received by the Crypto Purchaser associated with or otherwise attributable to the

Mining Equipment until the aggregate amount of such payments equals $250,000 and (b) thereafter, 50% of the monthly net revenues received

by the Crypto Purchaser associated with or otherwise attributable to the Mining Equipment until the aggregate amount of such payments

equals the Deferred Purchase Price, plus accrued interest (the “Crypto Sale”).

The Crypto Sale closed on January 23, 2024,

simultaneously with the execution of the Crypto Divestiture Agreement.

The full text of the Crypto Divestiture Agreement is

attached as Exhibit 2.3 to this Annual Report.

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.

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.

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

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.

addition to the sale of the Mining Equipment, we assigned, and the Crypto Purchaser assumed, all of our rights and obligations under

the Master Services Agreement, dated February 16, 2023, by and between Atlas Power Hosting, LLC (“Atlas”) and us (the “Atlas

MSA”), pursuant to which Atlas hosts, operates, and manages the Mining Equipment.

Pursuant to the Atlas MSA, the Crypto Purchaser

will receive payment in U.S.

dollars for the daily net mining revenue representing the dollar value of the cryptocurrency award generated

less power and other costs.

Bolt-on Acquisition

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.

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.

Initial Genesis Assets

acquired the Initial Genesis Assets in the Exok Transaction and the Exok Option Purchase, which includes the following assets:

of Exok’s right, title and interest in, to and under the fee oil and gas leases described more particularly in the Exok Agreement,

including all working interests, operating rights, record title interests and other interests of every kind and character (the “Fee

Leases”), that include and convey no less than a 75% net revenue interest (“NRI,” being the share of production

of all hydrocarbons produced, saved and sold, after all burdens, such as royalty and overriding royalty, have been deducted from

the working interest) in each Fee Lease;

of Exok’s right, title and interest in, to and under the State of Colorado Oil and Gas Lease described more particularly in

the Exok Agreement, including all working interests, operating rights, record title interests and other interests of every kind and

character (the “State Leases”), that include and convey no less than a 77.5% NRI in the State Leases;

of Exok’s leasehold interest (Fee Leases and State Leases collectively referred to as the “Leases”) in approximately

23,485 net mineral acres in, on and under approximately 37,189 gross acres located in Weld County, Colorado, as described more particularly

in the Exok Agreement (the “Lands”);

the extent transferable, Exok’s interests in and under all contracts, agreements and instruments by which the other Initial

Genesis Assets are bound or that relate to or are used or useful in connection with the ownership, development or operation of the

Leases or the Lands, to the extent applicable to the Leases or Lands, including all surface use agreements, surface rights, surface

permits and other similar rights and instruments;

of Exok’s records, files and geological and geophysical data directly related to the Initial Genesis Assets, including without

limitation all logs, core analyses, formation tests, films, surveyors’ notes, plane table sheets, shot point data bases, land

files, contract files, lease files, title files (including title reports, title opinions, runsheets, abstracts, evidence of bonus

and rental payments), maps, surveys and data sheets.

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%.

February 5, 2024, we acquired 1,280 gross leasehold acres on a drillable spacing unit and eight PUD drilling locations

in the DJ Basin (the “Genesis Bolt-on Assets”) from a private seller for $0.9 million.

intend to increase stakeholder value by using the following strategies to grow our reserves, production, and cash flow in a capital efficient

and environmentally conscious manner:

growth through the development of extensive drilling inventory and acreage.

We plan to target rich, immediately accessible

permitted locations and organically grow development through infill leasing.

We believe this will allow us to increase production,

reserves and cash flow which generate favorable returns.

drilling program with free cash flow and retain low leverage.

We aim to maintain a conservative financial position and develop primarily

through available cash flow from operations.

We plan to allocate capital in a disciplined manner and proactively manage our cost structure.

returns and capital efficiency.

We will utilize the latest technology in 3-D seismic mapping and geo-steering to decrease drill times

and improve well results.

Additionally, we will use our management’s extensive experience to deploy the latest drilling and completion

methodologies and apply the industry best practices to increase overall estimated ultimate recovery versus prior generation wells.

strategy focused on core area in the DJ Basin .

We plan to pursue accretive acquisitions through an opportunistic roll-up strategy

by continually evaluating acquisition opportunities to expand our position.

Our management team has a long track record of successfully

sourcing and integrating acquisitions.

manage regulatory, environmental, safety, and community matters.

Our development approach prioritizes the well-being of environment,

communities, and wildlife, and we actively engage with regulatory agencies to minimize surface impact while maximizing efficiency of

our development program.

Additionally, our operations emphasize utilizing technology and innovation to minimize impacts.

the closing of the Merger, we consummated the purchase of oil and natural gas leases from Exok, Inc.

(“Exok”), including

all of Exok’s right, title, and interest in, to and under certain undeveloped oil and natural gas leases located in Weld

County, Colorado, together with certain other associated assets, data, and records, for $3.0 million (the “Exok

Transaction”).

On August 15, 2023, we exercised the option we acquired in the Exok Transaction and purchased additional oil

and natural gas leases from Exok, consisting of approximately 25,240 net leasehold acres in, on and under approximately 32,580 gross

acres (the “Exok Option Purchase”) for total consideration of $25.3 million (collectively, the “Initial Genesis

On February 5, 2024, we acquired the Genesis Bolt–on Assets from a private seller for $0.9 million.

assets offset the other oil and natural gas assets held by us in northern Weld County, Colorado.

We refer to the Initial Genesis

Assets and the Genesis Bolt-on Assets, collectively, as the “Genesis Assets.”

of December 31, 2024, the total Genesis Assets include approximately 18,100 net leasehold acres in, on and under approximately 31,000

In August 2024, we began drilling eight wells on the Genesis Assets acreage which cover approximately 915 net leasehold acres

in, on and under approximately 1,115 gross acres.

These wells began producing in February 2025.

Approximately

87% of the net leasehold of our Initial Genesis Assets are leased from private landowners, with the remaining 13% under State of

Colorado leases.

The Initial Genesis Assets fee leases are burdened with total royalties of 25% and the State of Colorado leases are

burdened with total royalties of 22.5%.

All of our Genesis Bolt-on Assets are leased from private landowners and are burdened with

average royalties of 20%.

Further, none of the Genesis Assets leases are subject to federal leases.

All of the Genesis Assets

acreage is held by crude oil and natural gas leases with varying expiration dates, some with options to extend ranging from 1 to 4

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

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.

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.

Unless production is established within the spacing units covering the

undeveloped acreage, the leases for such acreage will eventually expire.

Genesis Assets are located in and around wells drilled in both the Niobrara Shale and the Codell Sandstone formations within the DJ Basin.

While production activities in the DJ Basin date back to the 1970s, production within the DJ Basin has increased rapidly since the horizontal

drilling boom in 2009, with both the Niobrara and Codell formations contributing to this activity.

Within our DJ Basin operating area,

there are over 1,300 legacy vertical wells, and the primary drilling objective in this area is crude oil production from the fractured

Codell and Niobrara formations.

The area has seen a renewed interest in drilling activity over the past decade in conjunction with drilling

success in the Niobrara in the DJ Basin on the front range of Colorado.

Active operators in the area include Chevron Corporation, Civitas

Resources, Inc., Verdad Resources LLC, Bison Oil and Gas, EOG Resources, Inc., Samson Energy Company, LLC, and others.

There is ample

takeaway infrastructure in place within several miles of the Genesis Assets, including multiple midstream operators such as Summit Midstream

Partners LP, Taproot Energy Partners LLC, Rimrock Energy Partners LLC, and NGL Energy Partners LP.

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.

is no guarantee that our development plan will result in the successful production of economic quantities of oil and gas.

has no operating history related to the exploration and production of oil and gas assets or drilling producing oil and gas wells.

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.

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.

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.

following table summarizes the permitting status of our identified well locations with respect to our Genesis Assets as of March 15, 2024:

Three Mile Lateral Count

Two Mile Lateral Count

We began executing the development plan of our Genesis Assets in the third quarter of 2024 by drilling

eight wells in the Shelduck South development, which all began producing in February 2025.

In order to continue the development plan

of our Genesis Assets, we plan to drill up to 6 gross wells in 2025 and up to 12 gross wells in 2026.

Our drilling plan is based on current commodity

prices, and an increase or decrease in commodity prices could impact the number of wells we actually drill.

is no guarantee that our development plan will result in the successful production of economic quantities of oil and natural gas.

Prior to the Shelduck wells, we had no operating history of drilling successfully producing oil and natural gas wells.

development plan is based on assumptions from management’s prior experience and such experience may not be indicative of the

success of our development plans.

We have historically incurred significant losses and experienced negative cash flow and have not

generated any revenue related to the exploration and production of oil and natural gas assets to date.

that permits are received in a timely manner is critical to our development plan.

With respect to our Initial Genesis Assets, on

November 27, 2023 we announced that we had submitted a Weld County Oil and Gas Location Assessment (“WOGLA”) application

for sites within the Genesis OGDP (“Genesis 1”) and had begun the application process for our second OGDP

(“Genesis 2”).

On February 1, 2024, the Burnett and Oasis locations within Genesis 1 were approved by the Weld County

hearings officer for the Genesis 1 WOGLA permits.

Genesis 1 and Genesis 2 encompass up to 72 gross wells and 48 gross wells,

respectively, from two pads each, with each pad developing nine-square miles of subsurface minerals.

The two pads in Genesis 1 are

expected to develop up to 18 gross three-mile lateral wells and 54 gross two-mile lateral wells.

In Genesis 2, the two pads are

expected to develop up to 16 and 32 gross three-mile lateral wells, respectively.

Following the September 15, 2023 submission of

Genesis 1 with the Colorado Energy and Carbon Management Commission (“CECMC”) for the Burnett and Oasis locations, a

hearing before the CECMC was held on March 13, 2024, in which the Genesis 1 OGDP received unanimous approval of the

commissioners.

following table summarizes the permitting status of our identified well locations with respect to our Genesis Assets as of December 31,

Expected Three

Mile Lateral Count

WOGLA Approved

1 unchanged sentence

CECMC Fully Permitted (1)

fully permitted wells.

Genesis Bolt-on Assets only, which were acquired in February 2024.

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

Permits and Authorizations.

of Our Reserve Estimates

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.

reserve report as of December 31, 2023, which should be read in its entirety, is attached as Exhibit 99.1 to this Annual Report.

Reserve Data (1)

Estimated possible reserves

the Genesis Bolt-on Assets only, which were acquired in February 2024.

more information regarding regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas

Industry—Related Permits and Authorizations below.

January 11, 2024, we entered into the NRO Agreement to acquire the Central Weld Assets, located in the DJ Basin in Weld County,

Colorado for total consideration of $94.5 million, subject to certain closing price adjustments and other customary closing

On August 15, 2024, we and NRO agreed to amend certain terms of the NRO Agreement, pursuant to which, total

consideration of the NRO Acquisition was reduced to $84.5 million in cash, subject to certain closing price adjustments and other

customary closing conditions.

On October 1, 2024, we closed the NRO Acquisition and paid $49.6 million to the sellers in cash, using

cash on hand, the proceeds from the issuance of Common Stock, and a portion of the proceeds from the issuance of the Senior

Convertible Note (as defined herein).

We completed the final settlement with NRO in December 2024, which resulted in a final

purchase price of $55.5 million.

of December 31, 2024, the Central Weld Assets cover approximately 5,640 net leasehold acres, on and under approximately 6,000 gross

acres and 63 gross proved undeveloped locations, all of which have approved well permits and 26 gross operated horizontal wells.

Since the closing of the NRO Acquisition, we have added 14 additional gross proved undeveloped locations to the Central Weld Assets.

Approximately 85% of the net leasehold of our Central Weld Assets are held by production and almost all of the acreage is leased

from private landowners.

The Central Weld Assets fee leases are burdened with average royalties of 20%.

The remaining 15% of the

Central Weld Assets acreage not held by production have varying expiration dates, some with options to extend ranging from one to

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.

Plan and Permitting.

We plan to begin executing the development plan of our Central Weld Assets at the end of the first quarter

of 2025 by drilling 14 gross wells on the Rusch pad.

We expect these wells to come online at the beginning of the third quarter of

We then plan to drill seven gross wells on our Noble pad, which should come online in the third quarter of 2025.

Additionally,

we plan to drill up to a total of 57 gross wells in 2025 and up to 51 gross wells in 2026, with all proved undeveloped reserves

scheduled to be converted to developed status within five years.

Our drilling plan is based on current commodity prices, and an

increase or decrease in commodity prices could impact the number of wells we actually drill.

is no guarantee that our development plan will result in the successful production of economic quantities of oil and natural gas.

to the Shelduck wells, we had no operating history of drilling successfully producing oil and natural gas wells.

Our development plan

is based on assumptions from management’s prior experience and such experience may not be indicative of the success of our development

We have historically incurred significant losses and experienced negative cash flow and have not generated any revenue related

to the exploration and production of oil and natural gas assets to date.

that permits are received in a timely manner is critical to our development plan.

As of December 31, 2024, all 63 of the 77 gross

undeveloped Central Weld Asset locations are WOGLA approved and CECMA approved and permitted.

For more information regarding

regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas Industry—Related Permits and

Authorizations.

Our reserve estimates as of December 31, 2024, are

based on a reserve report prepared by Cawley, Gillespie & Associates Inc.

(“CG&A”) in accordance with the rules and

regulations of the SEC in Regulation S-X, Rule 4-10, and do not include probable or possible reserves.

All of our proved reserves presented

below are located in the DJ Basin.

Additionally, we did not have any estimated proved reserves as of December 31, 2023.

Our estimated proved reserves and the related net revenues were determined

using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December

(“SEC Prices”).

The SEC Prices are adjusted for treating costs and/or crude quality and gravity corrections.

ended December 31, 2024, SEC Prices, inclusive of adjustments, used in the calculations were $74.63 per Bbl of oil, $1.60 per Mcf of natural

gas, and $21.63 per Bbl of NGLs.

following table presents our estimated proved reserves by category as of December 31, 2024:

Natural Gas (MMcf)

Natural gas liquids (MBbl)

Total estimated possible

reserves ( M Boe) (2)

Percent oil and liquids

reserves were calculated using SEC prices, which were $78.22 per Bbl for oil and $2.637 per Mcf for natural gas for the year ended

Standardized Measure

Proved developed producing

Proved developed non-producing

Total proved developed

Proved undeveloped

a ratio of 6 MMcf of natural gas per MBoe.

Reconciliation

of Standardized Measure to PV-10

is a financial measure not presented in accordance with U.S.

is derived from the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”), which is the most directly

comparable GAAP financial measure for proved reserves.

PV-10 is a computation of the Standardized Measure on a pre-tax basis and is equal

to the Standardized Measure at the applicable date, before deducting future income taxes discounted at 10%.

Neither PV-10 nor Standardized

Measure represents an estimate of the fair market value of the applicable crude oil, natural gas, and NGLs properties.

We believe that

the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the Standardized Measure, or after-tax

amount, because it presents the discounted future net cash flows attributable to our reserves before considering future corporate income

taxes and our current tax structure.

While the Standardized Measure is dependent on the unique tax situation of each company, PV-10 is

based on prices and discount factors that are consistent for all companies.

The following table provides a reconciliation of the Standardized Measure

to the PV-10 of our estimated proved reserves for the period presented:

December 31, 2024

Adjustments were made for location and grade.

Assumes a ratio of 6 MMcf of natural gas per MBoe.

(In thousands)

Standardized Measure

Present value of future income taxes discounted at 10%

Proved Developed Reserves

Proved developed oil and natural gas reserves are reserves which can be

expected to be recovered through existing wells with existing equipment and operating methods.

following table presents the changes in our estimated proved developed reserves during the year ended December 31, 2024:

Proved developed reserves as of January 1, 2024

Acquisitions of reserves

Proved developed reserves as of December 31, 2024

of December 31, 2024, our estimated proved developed reserves are 6.4 MMBoe, which are comprised of the proved developed reserves acquired in the NRO Acquisition,

which closed on October 1, 2024.

Proved Undeveloped Reserves

PUD oil and natural gas reserves are reserves which are expected to be

recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.

PUD reserves on undrilled acreage are limited to those directly offsetting development spacing areas which are reasonably certain of production

when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater

following table presents the changes in our estimated PUD reserves during the year ended December 31, 2024:

Proved undeveloped reserves as of January 1, 2024

Converted to proved developed reserves

Acquisitions of reserves

Revisions to previous estimates

Proved undeveloped reserves as of December 31, 2024

As of December 31, 2024, our estimated PUD reserves

are 19.7 MMBoe, which includes reserve acquisitions of 22.3 MMBoe, approximately 19.7 MMBoe of which relate to the NRO Acquisition, which

closed on October 1, 2024.

The remaining acquired reserves were our Shelduck locations, which we acquired in February 2024 and began developing

These reserves were converted to proved developed non-producing by year end as a result of successful drilling efforts.

reviews all PUD reserves on an annual basis to ensure an appropriate plan for development exists.

As per SEC rules, all of our PUD reserves

are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves, unless

the reserves are associated with an existing producing zone.

We expect that development costs associated with our estimated PUD reserves

as of December 31, 2024 will require us to invest an additional $290.0 million for those reserves to be brought to production.

to make the necessary investments to generate these cash inflows is subject to factors that may be beyond our control.

Refer to Risk

Factors - The development of our estimated PUD reserves may take longer and may require higher levels

of capital expenditures than we currently anticipate.

Therefore, our estimated PUD reserves may not

ultimately be developed or produced.

of Reserves Estimates

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.

proved reserve estimates as of December 31, 2024 have been prepared

by CG&A, an independent Petroleum Reserve Evaluation Firm.

No director, officer,

or key employee of CG&A has any financial ownership in us or any of our affiliates.

CG&A’s compensation for the preparation

of its report is not contingent upon the results obtained and reported.

CG&A has not performed other work for us or any of our affiliates

that would affect its objectivity.

The estimates of our reserves presented in the CG&A reserve report were overseen by W.

Todd Brooker.

Our full reserve report as of December 31, 2024, prepared by CG&A, should be read in its entirety, and is

attached as Exhibit 99.1 to this Annual Report.

Brooker is the President of CG&A and has been an employee of CG&A since 1992.

5 unchanged sentences

Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA.

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).

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”).

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.

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

The technical and economic data used in the estimation of our possible reserves include, but are not limited to, lease positions,

The technical and economic data used in the estimation of our reserves include, but are not limited to, lease positions,

estimated working and net revenue interests, indicative drilling and completion costs, facility and pipeline costs, expected operating

14 unchanged sentences

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

Refer to Risk Factors— Our estimated oil, natural gas and NGLs reserves are based on many assumptions that may prove to be

Any material inaccuracies in the reserve estimates or the underlying assumptions will materially affect the quantities and

present value of our reserves .

Controls and Qualifications of Technical Persons

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 .”

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

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.

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:

Controls over Reserve Estimates and Reserve Estimation Procedures

have assembled an internal technical team composed of reservoir engineers, geologists, land, and management members, which meet with

the independent reserve engineers periodically during the period covered by the reserve reports to discuss the assumptions and methods

used in the proved reserve estimation process.

We provide historical information to the independent reserve engineers for

its properties such as ownership interest, oil and natural gas production, well data, commodity prices and operating and development

preparation of our proved reserve estimates is completed in accordance with our internal control procedures.

These procedures,

which are intended to ensure reliability of reserve estimations, include the following:

and verification of historical production data of offset operators, working interests, net revenue interest, lease operating statements,

capital costs, severance and ad valorem taxes, which as of this filing, has been derived from data from offset third-party operators;

of property ownership by the Company’s land department;

the preparation of reserve estimates by the Company’s Executive Vice President of Operations;

by the Company’s President of all of the Company’s reserves, including the review of all significant reserve changes

and all new proved and possible undeveloped reserves additions;

reporting responsibilities and final approval by the Company’s Chief Executive Officer and the Company’s President.

Freeman, our Executive Vice President of Operations, works closely with CG&A to ensure the integrity, accuracy and timeliness of

of property ownership by our land department;

the preparation of reserve estimates by our Executive Vice President of Operations;

by our President of all of our reserves, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

reporting responsibilities and final approval by our Chief Executive Officer and President.

Qualifications

of Technical Persons

Smith, our Senior Vice President of Engineering, works closely with CG&A to ensure the integrity, accuracy and timeliness of

data furnished to our independent reserve engineers in their preparation of reserve estimates.

Freeman is primarily responsible for

overseeing the preparation of both our internal and external reserve estimates.

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.

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.

Company does not have any delivery commitments as of December 31, 2023 or 2022.

Company does not have any productive wells as of December 31, 2023 or 2022.

Smith is primarily responsible

for overseeing the preparation of both our internal and external reserve estimates.

Smith is responsible for reservoir

engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing our independent reserve

engineers during the preparation of our external reserve estimates.

His professional qualifications meet or exceed the

qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and

Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers.

Smith’s qualifications include

a Bachelor of Arts Degree in Geology from the University of Colorado at Boulder, a Master of Science Degree in Civil Engineering

from Colorado State University, and a Master of Science Degree in Petroleum Engineering from the University of Southern California.

Additionally, he has 15 years of practical experience in estimating and evaluating reserve information, the majority of which have

included overseeing, estimating, and evaluating reserves and is a member of SPE.

Average Sales Prices, and Production Costs

production volumes, average sales prices and average production costs are as follows:

Years Ended December 31,

Natural gas (MMcf)

Total production (MBoe)

Average sales price (excluding effects of derivatives):

Oil (per MBbls)

Natural gas (per MMcf)

NGL (per MBbls)

Average price (per MBoe)

Average lease operating expenses (per Boe)

additional information, refer to Part II - Item 7.

Management’s Discussion and Analysis of Financial Condition and Results

of Operations .

following table sets forth a summary of our operated development and exploratory drilling well activity for the year ended December 31,

We did not have any development or exploratory drilling activities during the year ended December 31, 2023.

Gross wells are the total number of wells we drilled in which we have an interest, and net wells are the sum of our

fractional working interests owned in gross wells.

Productive wells (2)

Dry wells (3)

Development wells consist of wells completed and/or turned to sales during

the period, regardless of when drilling was initiated.

productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities

to justify completion as an oil or natural gas producing well.

Productive wells are included in the table in the year they were determined

to be productive, as opposed to the year the well was drilled.

All of our drilled development productive wells have come online in February 2025.

dry well is an exploratory or development well that is not a productive well.

Dry wells are included in the table in the year they

were determined not to be productive, as opposed to the year the well was drilled.

wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence

deliveries and crude oil wells awaiting connection to production facilities.

Gross wells are the total number of productive wells in

which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

following table presents information about our productive wells as of December 31, 2024.

We did not have any productive wells as of December

Productive wells

following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as

of December 31, 2024.

The Company did not have any developed or undeveloped acreage for which it owned a working interest as of December

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.

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

Company has not had any development or exploratory drilling activities as of December 31, 2023 or 2022.

Developed Acres

Undeveloped Acres

leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless

production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the

cessation of production.

Approximately 15,810 net acres, or 66%, of our total net acres may expire in the next three years if production

is not established or if we do not extend lease terms.

We intend to extend our strategic leases to the extent possible.

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.

following table sets forth the undeveloped acreage, as of December 31, 2024, which will expire in the years indicated unless production

is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions

prior to the primary term expiration dates.

Expiring 2025

Expiring 2026

Expiring 2027

Expiring 2028

to Properties

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of our business.

Price Risks and Price Risk Management Activities

from our properties is marketed using methods that are consistent with industry practices.

Sales prices for oil and natural gas

production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations,

distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions.

In an effort to reduce

the impact of price volatility, and in compliance with requirements under our Credit Facility Agreement (as defined below), we enter

into derivative contracts to economically hedge a portion of our estimated production from our proved, developed, producing oil and

natural gas properties against adverse fluctuations in commodity prices.

By doing so, we believe we can mitigate, but not eliminate,

the potential negative effects of decreases in oil and natural gas prices on our cash flows from operations.

However, our hedging

activity could reduce our ability to benefit from increases in oil and natural gas prices.

Further, we could sustain losses to the

extent our oil and natural gas derivative contract prices are lower than market prices and, conversely, we could recognize gains to

the extent our oil and natural gas derivative contract prices are higher than market prices.

For additional information, refer to

Part II - Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of

did not have any producing wells prior to the NRO Acquisition, which closed on October 1, 2024.

Following the NRO Acquisition, during

the fourth quarter of 2024, two of our largest customers accounted for approximately 80% and 15% of our oil, natural gas, and NGL revenues.

Those same two customers accounted for approximately 78% and 20% of our accrued oil, natural gas, and NGL revenues.

We do not believe

the loss of any single purchaser would materially impact our operating results, as crude oil, natural gas, and NGL are fungible products

with well-established markets and numerous purchasers.

Company does not have any delivery commitments as of December 31, 2024 or 2023.

oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that often have greater

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The effect and potential impacts of these risks are difficult to accurately predict.

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.

“ Risk Factors— We will face strong competition from other oil and gas companies.

International

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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.

Refer to Risk Factors— Oil, natural

gas and NGLs prices are highly volatile.

An extended decline in commodity prices may adversely affect our business, financial condition

or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

of the Oil and Natural Gas Industry

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or any future rulemaking, will not have a material and adverse impact on our financial position, cash flows, or results of operations.

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.

In addition, governmental, scientific, and public concern over the threat

of climate change arising from increasing global emissions of greenhouse gases (“GHGs”) has resulted in higher political and

regulatory risks in the U.S., including climate change-related pledges made by certain administrations.

During his administration, former

President Biden issued several executive orders focused on addressing climate change, which may impact the costs to produce, or demand

for, oil and natural gas.

Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the U.S.:

Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which established a roadmap to net zero emissions in the U.S.

by 2050 through,

among other things, improving energy efficiency;

decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels;

reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide.

Given the directives issued by the current administration

to withdraw the U.S.

from the Paris Agreement on climate change, it is likely that these policies will be rescinded by the present administration.

of Production of Oil, Natural Gas, and NGLs

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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,

of oil, natural gas and NGLs that we can produce from our wells and limiting the number of wells or the locations where we can drill,

although we can apply for exceptions to such regulations, including applications to increase well densities and reduce lease boundary

setbacks to more effectively recover oil and 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.

setbacks to more effectively recover oil and natural gas resources.

Moreover, Colorado imposes a production or severance tax with respect

to the production and sale of oil, natural gas, and NGLs within its jurisdiction.

also regulates drilling and operating activities by requiring, among other things, permits for new pad locations, the drilling of wells,

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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.

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

Army Corps of Engineers (the “Corps”) have issued rules attempting to clarify the federal

jurisdictional reach over WOTUS since 2015, including the Navigable Waters Protection Rule during the first Trump administration,

rules reverting back to the 1986 WOTUS definition during the Biden administration, and rules reinstating the pre-2015 definition in

January of 2023.

However, in May 2023, the Supreme Court decided Sackett v.

EPA, which sharply curtailed the EPA’s and

Corps’ jurisdictional reach by limiting the types of wetlands that fell under WOTUS.

Sackett codified the definition of WOTUS

as only geographical features that are described in ordinary parlance as “streams, oceans, rivers, and lakes” and to

adjacent wetlands that are “indistinguishable” from those bodies of water due to a continuous surface connection.

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

As such, uncertainty remains with respect to future implementation of the rule and any resulting litigation.

primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends

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produced water disposal, may reduce our profitability.

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

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.

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

The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources

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.

future implementation of the standards is uncertain at this time.

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.

The federal Clean Air Act (the “CAA”) and comparable state

laws restrict the emission of air pollutants from many sources, such as tank batteries, through air emissions standards, construction

and operating permitting programs and the imposition of other compliance standards.

These laws and regulations may require us to obtain

pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air

emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control

emissions of certain pollutants.

The need to obtain permits has the potential to delay the development of our projects.

Recently, there

has been increased regulation with respect to air emissions from the oil and natural gas sector.

In June 2016, the EPA published final New Source Performance Standards

(“NSPS”) at 40 CFR Part 60, Subpart OOOOa establishing new air emission controls for methane and volatile organic compound

(“VOC”) emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category,

including production, processing, transmission and storage activities, as an iteration to the previous standards at Subpart OOOO.

EPA announced the latest iterations on these standards, Subpart OOOOb and OOOOc, on December 2, 2023.

These rules require the phase-out

of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations, as well as

emissions standards for existing sources.

The final rule gives states, along with federal tribes that wish to regulate existing sources,

two years to develop and submit their plans for reducing methane from existing sources followed by three years from the plan submission

deadline for existing sources to comply.

The regulations are subject to legal challenge and will also need to be incorporated into the

states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to

legal challenge.

In addition, the new rules have been appealed by various parties and it is also possible that the new presidential administration

will seek to revise or retract these rules.

As a result, future implementation of the standards is uncertain at this time.

The EPA also finalized separate rules under the CAA in June 2016 regarding

criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and natural gas

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.

of GHG Emissions

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.

the SEC issued a final rule in March 2024 that would mandate disclosure of climate-related risks, including financial impacts,

In response to findings in 2009 that emissions of carbon dioxide, methane

and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA, including

rules requiring the monitoring and annual reporting of GHG emissions from large GHG emission sources in the U.S., including certain onshore

and offshore natural gas, oil and NGL production sources, which include certain of our operations.

An executive order, signed on January

20, 2025, instructed the EPA and other agency heads to brief the White House on the “legality and continuing applicability”

of the 2009 endangerment findings.

This could presage an attempt to void the 2009 findings, which, if successful, could result in voiding

many of the EPA’s rules for GHG emissions.

The EPA in July 2023 issued a proposed rule to expand the scope of its

Greenhouse Gas Reporting Program for certain petroleum and natural gas facilities.

The proposed rule would make the reach of the program

both broader and more granular, creating reporting obligations for a wider set of methane and other gas emissions events and requiring

increased technical detail for certain other preexisting reporting obligations.

The rule was finalized in May of 2024 with an effective

date of January 1, 2025.

This rule could raise our costs of regulatory compliance.

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

Smaller reporting companies

will be required to incorporate discussion of these risks in filings beginning in fiscal year 2027 and will not be required to report

GHG emissions data.

Large accelerated filers and accelerated filers will be required to incorporate such discussion in fiscal years 2025

and 2026, respectively, as well as disclose Scope 1 and 2 GHG emissions, if material, in fiscal years 2026 and 2027, and provide third

party attestation reports related to such emissions beginning in fiscal years 2029 and 2031.

However, this rule has been challenged and,

on February 11, 2025, the Acting Chairman of the SEC stated that the commission will pause litigation on this rule.

the United Nations-sponsored Paris Agreement calls for countries to set their own GHG emissions targets and be transparent about the

measures each country will take to achieve its GHG emissions targets.

However, the Paris Agreement does not impose any binding obligations

on its participants.

Former President Biden recommitted the U.S.

to the Paris Agreement and, in April 2021, announced a goal of reducing

the U.S.’ emissions by 50-52% below 2005 levels by 2030.

Incremental reduction measures have been agreed to at subsequent meetings,

Conference of the Parties (“COP”) 26 held in Glasgow in November 2021, COP27 held in Sharm-El Sheik in November 2022, COP28

held in Dubai in November to December 2023 and COP29 held in Baku in November 2024.

Relatedly, the U.S.

and European Union jointly announced

the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020

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.

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.

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.

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;

effects were to occur, they could have an adverse effect on our exploration and production operations.

levels, including “all feasible reductions” in the energy sector, which was reaffirmed at COP27.

However, on January 20,

2025, President Trump signed an executive order to start the process of withdrawing the U.S.

from the Paris Agreement.

This signals that

will also not provide funding or otherwise adhere to the nonbinding commitments made in subsequent COPs.

In addition, the Inflation Reduction Act of 2022 (the “IRA”),

signed by former President Biden in August 2022, provides significant funding and incentives for research and development of low-carbon

energy production methods, carbon capture, and other programs directed at addressing climate change.

The IRA also includes a methane emissions

reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas

This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are

already required to report under EPA’s Greenhouse Gas Reporting Program.

On November 18, 2024, the EPA published a final rule imposing

a charge for “waste methane” emissions from the oil and gas sector.

The amount of the charge is $900 per metric ton of methane

emitted in 2024, $1,200 per metric ton for emissions in 2025 and $1,500 per metric ton for 2026 and beyond.

This rule may result in significant

costs for our operations.

On February 4, 2025, a joint resolution was proposed to void this rule under the Congressional Review Act.

if the joint resolution is approved, it may not eliminate the waste methane fee because the fee was mandated by the IRA.

Although it is not possible at this time to predict how new laws or regulations

that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements

imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to

incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions

from new or modified sources.

In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas,

oil and NGLs we produce and lower the value of our reserves.

Finally, it should be noted that increasing concentrations of GHGs in the

Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity

of storms, floods, droughts and other extreme climatic events;

if any such effects were to occur, they could have an adverse effect on

our operations.

Fracturing Activities

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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.

For example, Colorado has promulgated rules that require oil and natural gas operators to disclose the volume of

water and all chemicals used during the hydraulic fracturing process to an online registry.

the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate,

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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.

Over the past several

years, the CECMC has approved new rules regarding various matters, including wellbore integrity, hydraulic fracturing, well control,

waste management, spill reporting, spacing of wells and pooling of mineral interests, and an increase in potential sanctions for

CECMC rule violations.

We do not believe that any of these CECMC rules will affect us in a way that materially differs from the way

they will affect other oil and natural gas producers, gatherers, and marketers with which we compete.

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.

natural gas exploration and production activities.

SB 181 changed the CECMC’s mission from “fostering” responsible

and balanced development “consistent with protection” of public health and the environment to “regulating” development

“to protect” public health and the environment.

SB 181 also instituted several state-wide regulatory changes, namely it:

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;

(i) changed Colorado’s statutory pooling provisions to require an applicant to own, or obtain the consent of, more than 45% of

the applicable working or mineral interest, whereas previously the consent of only one mineral interest owner was required;

(ii) requires

that, after production is established, an applicant must pay force-pooled working or mineral interest owners a 16% royalty on oil production

and a 13% royalty on gas production;

(iii) changed state pre-emption law to afford local governments greater control over oil and natural

and (iv) initiated a comprehensive rulemaking to amend CECMC’s rules consistent with the agency’s revised mission.

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.

and surface impacts associated with oil and natural gas development.

Whether an applicable local government determines to implement regulatory

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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.

can inspect oil and natural gas operations and impose fines for leaks and spills.

Regulation in the municipalities and areas where we

operate could result in increased costs, delays in securing permits and other approvals related to our operations, and otherwise materially

impact our ability to operate and drill new wells in the areas where we hold oil and natural gas interests.

CECMC has adopted significant additional regulations to implement SB 181.

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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.

Most recently, the CECMC is considering a draft rulemaking regarding the cumulative impacts of oil and natural

gas operations, including increased scrutiny on a project’s proximity to other industrial sites, residential and school areas,

DI communities, and “cumulatively impacted communities.” The draft rules would also set GHG emissions intensity targets for

oil and natural gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential

to restrict operations during the summer in Ozone Nonattainment Areas.

Depending on how these and any other new rules are applied and

enforced, they could add substantial increases in well costs for our Colorado operations.

The rules could also impact our ability to

operate and extend the time necessary to obtain drilling permits, which would create substantial uncertainty about future development

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.

oil and natural gas facilities.

The CDPHE and AQCC adopted more stringent standards for leak detection and repair inspection frequency,

pipeline and compressor station inspection and maintenance frequencies, and for reducing emissions from pneumatic devices.

2019, the AQCC also expanded storage tank control and loadout control requirements.

The legislation also grants the CDPHE and AQCC regulatory

authority over a broad range of oil and natural gas facilities during pre-production activities, drilling, and completion.

On December 20, 2024, the CDPHE adopted new rules to reduce GHG emissions

from midstream oil and gas operations that the agency touted as “first-of-its-kind.” Under these rules, midstream operators

must capture and recover hydrocarbon emissions from activities such as pipeline pigging and blowdown of equipment.

These new requirements

may increase overall costs for the oil and gas industry in Colorado.

It is possible that the CDPHE will propose additional rules to reduce

emissions from other segments of the oil and gas sector.

Permits and Authorizations

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projects and cease production or operation of wells, pipelines and other operations.

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

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

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.

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.

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.

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.

example, when obtaining a permit for new multi-well pads, the State of Colorado Oil and Gas Development Plans (“OGDP”)

approval process may be pursued concurrently with the county approval process.

Thirty days prior to the initial filing for a permit,

we are required to provide notice to relevant local government authorities, proximate local governments and schools within 2,000

feet of our proposed site.

Following such notice, a development plan may be filed, subject to potential requests for hearings and

consultation, with such process lasting on average between 90 and 150 days.

Upon approval by state authorities, a development plan

will be subject to a 30-day public comment period (or 45 days in the case of a plan contemplating drilling within 2,000 feet of a DI

community), with such period subject to extension at the discretion of state authorities.

Upon completion of the public comment

period, the CECMC Director will make a recommendation to approve, approve with conditions of approval, or deny the development plan.

The CECMC will then hold a hearing to determine whether to approve, deny or stay an application 7 to 14 days after the

recommendation of the CECMC Director.

If the development plan is approved, drilling on the applicable pad may commence after a 60-

to 90-day wellbore permitting administrative process.

Concurrent with the state approval process, the WOGLA application for construction

of improvements related to oil and gas exploration and production in Weld County, Colorado, will be subject to approval by the Weld County

Oil and Gas Energy Department.

Prior to the application, a meeting hosted by Weld County will review all alternate locations within the

development area attended by all other relevant state and local regulatory agencies.

Following the pre-application meeting, a 30-day notice

is submitted to Weld County stating a WOGLA application will be filed.

Subsequently, a WOGLA application may be filed with a public intervention

period occurring 20 days prior to a hearing.

The hearing for WOGLA applications is scheduled for a minimum of 45 days from the date of

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.

maintain insurance against some risks associated with above or underground contamination that may occur as a result of these activities.

However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to

be commercially available or that this insurance will be available at premium levels that justify its purchase by us.

The occurrence

of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition

and operations.

Cryptocurrency

1 unchanged sentence

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.

Refer to Recent Developments—Sale

of Crypto Assets.

Accordingly, we do not currently have and do not expect to have any cryptocurrency mining operations in the future.

Following the Crypto Sale, our exposure to the market prices of cryptocurrencies is limited to the ability of the Crypto Purchaser to

pay the deferred purchase price pursuant to the Crypto Divestiture Agreement.

Refer to Recent Developments—Sale of Crypto Assets,

Risk Factors—We may not realize the full benefit of the Crypto Sale for a variety of reasons, including the inability of the Crypto

Purchaser to pay the Deferred Purchase Price due to a decrease in the price of Bitcoin or the actions of third parties and the Crypto

Divestiture Agreement.

cryptocurrency mining activities during 2022 consisted of participation in mining pools that pooled the resources of groups of miners

5 unchanged sentences

Under the Atlas MSA,

we do not own, control or take custody of any Bitcoin produced by the Mining Equipment.

we did not own, control or take custody of any Bitcoin produced by the Mining Equipment.

Instead, Atlas, as service provider, retained

4 unchanged sentences

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.

Affecting Profitability

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.

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

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.

of December 31, 2023, approximately $12 million has been invested to acquire our miners.

Creek Road paid for these miners in cash.

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.

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.”

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:

December 31, 2023 (1)

Bitcoin price

Power cost per Bitcoin

Cash operating margin per Bitcoin

Hardware cost per Bitcoin

Total operating margin per Bitcoin

Key inputs to power cost:

Approximate average network

hash rate (EH/s)

Average energy consumption

per miner (watts) (2)

Electricity cost ($ per

Approximate average energy

consumption per Bitcoin (kWh)

based on a daily average from May 3, 2023, the closing date of the Merger, to December 31, 2023.

value represents the weighted average energy consumption per miner.

This is a rated value as measured by the manufacturer of our

miners, Bitmain.

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

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.

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.

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.

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.

Services Agreement – Atlas

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.

related to cryptocurrency mining activities are not presented in Part II.

Item 7 - Management’s Discussion and Analysis of Financial

Condition and Results of Operations or the accompanying financial statements.

do not currently own any intellectual property.

of December 31, 2024, we employed 19 full-time employees.

We have never experienced a work stoppage, and believe we maintain

positive relationships with our employees.

We have never experienced a work stoppage, and believe we maintain positive

relationships with our employees.

of December 31, 2024, we have leased office space in Houston, Texas, where our principal offices are located, and in Denver, Colorado.

Information, Website and Availability of Public Filings

principal executive offices are located at 602 Sawyer Street, Suite 710, Houston Texas 77007.

principal executive offices are located at 55 Waugh, Suite 400, Houston, Texas 77007.

We also maintain an office in Denver, Colorado.

7 unchanged sentences

link as soon as reasonably practicable after they are filed or furnished with the SEC.

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.

common stock is listed and traded on The Nasdaq Stock Market under the symbol “PROP.”

on our website is not incorporated into this Annual Report or our other filings with the SEC and is not a part of them.

common stock is listed and traded on the Nasdaq Capital Market under the symbol “PROP.”

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business