Prairie Operating Co. (PROP) FY 2024 MD&A

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

The
following discussion and analysis of our financial condition and results of operations for the year ended December 31, 2024 and 2023
should be read in conjunction with our consolidated financial statements and related notes to those financial statements and other financial
information appearing in this Annual Report.

Our
discussion includes forward–looking statements based upon current expectations that involve risks and uncertainties, such as our
plans, objectives, expectations and intentions. Actual results and the timing of events could differ materially from those anticipated
in these forward–looking statements as a result of a number of factors, including those described under the headings “Risk
Factors” and “Cautionary Statement Regarding Forward-Looking Statements” appearing elsewhere in the Annual Report.
Except as otherwise indicated or required by the context, references to the “Company,” “we,” “us,”
“our” or similar terms refer to Prairie Operating Co.

Overview

We
are an independent oil and gas company focused on the acquisition and development of crude oil, natural gas, and NGLs. Our assets
and operations are strategically located in the oil region of rural Weld County, within the DJ Basin. We believe the DJ Basin to be one
of the premier resource plays in the U.S. Weld County boasts some of the lowest break-even prices in the U.S., and has a long production
history that has proven and consistent results. The productivity of this resource is demonstrated by the integral role that Weld County
holds in Colorado’s energy economy, having produced 82% of Colorado’s oil production as of December 2024.

We seek to deliver energy in an environmentally efficient manner by deploying
next-generation technology and techniques. In addition to growing
production through our drilling operations, we also seek to grow our business through accretive acquisitions, focusing on assets with
the following criteria: (i) producing reserves, with opportunities to add accretive, undeveloped bolt–on acreage; (ii) ample, high
rate–of–return inventory of drilling locations that can be developed with cash flow reinvestment; (iii) strong well–level
economics; (iv) liquids–rich assets; and (v) accretive valuation.

As
of December 31, 2024, our E&P assets consist of our Central Weld Assets, Genesis and Genesis Bolt–on Assets, and the Exok
Option Purchase assets. Our Central Weld Assets were acquired from NRO in October 2024 and included 26 revenue producing oil and
natural gas wells. Our total Genesis Assets include approximately 18,100 net leasehold acres in, on and under approximately 31,000 gross
acres and our Central Weld Assets include approximately 5,640 net leasehold acres, on and under approximately 6,000 gross
acres. We commenced drilling wells on our Genesis Bolt-on Assets in the third quarter of 2024 and all eight wells began producing in
February 2025.

Recent
Developments

Bayswater Acquisition

On
February 6, 2025, we and certain of our subsidiaries entered into the Bayswater PSA with 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.

The Bayswater Acquisition has an outside closing date of March 15, 2025,
subject to customary closing conditions, with an economic effective date of December 1, 2024. However, there can be no assurance that a closing will occur.
The Bayswater PSA contains customary representations, warranties and covenants of us and Bayswater for a transaction of this nature.

Development
Program Launch

During
the third quarter of 2024, we commenced our initial drilling program, starting with an 8-well pad on Shelduck South, part of the
Genesis Bolt–on Assets acquired in February 2024. The Shelduck South development consists of eight two-mile lateral wells
across 1,115 gross leasehold acres, targeting the Niobrara B and C formations. We spud our first well on September 5, 2024 and all
eight wells began producing in February 2025.

NRO
Acquisition

On
January 11, 2024, we entered into the NRO Agreement to acquire the Central Weld Assets, located in the DJ Basin in Weld County, Colorado
for total consideration of $94.5 million, subject to certain closing price adjustments and other customary closing conditions. The Purchase
Price consisted of $83.0 million in cash and $11.5 million in deferred cash payments. Pursuant to the NRO Agreement, we deposited $9.0
million of the Purchase Price into an escrow account on January 11, 2024.

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, and the parties agreed to remove the deferred cash payments. Additionally on August 15, 2024, $6.0 million of the
Deposit was released to NRO and the remaining $3.0 million was returned to us.

On October 1, 2024, we closed the NRO Acquisition and paid $49.6 million
to the sellers in cash, using cash on hand, the proceeds from the issuance of Common Stock, and a portion of the proceeds from the issuance
of the Senior Convertible Note. We completed the final settlement with NRO in December 2024, which resulted in a final purchase price
of $55.5 million.

Credit
Facility

On December 16, 2024, we, as borrower, entered into a reserve-based credit
agreement with Citibank, N.A. (“Citi”), as administrative agent and the financial institutions party thereto (the “Credit
Facility Agreement”), which has a maximum credit commitment of $1.0 billion and is set to mature on December 16, 2026 (collectively,
the “Credit Facility”). The Credit Facility is guaranteed by all of our restricted subsidiaries and is secured by a first-priority
security interest on substantially all of our oil and natural gas properties and substantially all of our personal property assets, subject
to customary exceptions. As of December 31, 2024, the Credit Facility had a borrowing base and an aggregate elected commitment of $44.0
million and a $5.0 million sublimit for the issuance of letters of credit. The borrowing base is subject to semi-annual redeterminations
based upon the value of our oil and gas properties as determined in a reserve report dated as of January and July of each year, subject
to certain interim redeterminations.

58

As
of December 31, 2024, we had $28.0 million of revolving borrowings and no letters of credit outstanding under the Credit Facility,
resulting in $7.2 million of availability for future borrowings and letters of credit. Refer to Liquidity and Capital Resources -
Significant Sources of Liquidity below for a further discussion of the Credit Facility. On February 3, 2025, we entered into the
First Amendment to the Credit Facility Agreement (the “First Amendment”), which among other things, increased the
borrowing base and the aggregate elected commitments to $60.0 million.

Standby
Equity Purchase Agreement

On
September 30, 2024, we entered into a Standby Equity Purchase Agreement (the “SEPA”) with YA II PN, LTD., a Cayman
Islands exempt limited company (“Yorkville”), whereby, subject to certain conditions, we have the right, not the
obligation, to sell to Yorkville up to $40.0 million shares of Common Stock, at any time and in the amount as specified in the
Company’s request (“Advance Notice”), during the commitment period commencing on September 30, 2024 (the
“SEPA Effective Date”) and terminating on September 30, 2026. Each issuance and sale of shares by us to Yorkville
pursuant to the SEPA (“Advance”) is subject to a maximum limit equal to 100% of the aggregate volume traded of our
Common Stock on the Nasdaq Stock Market during the five trading days immediately prior to the date of the Advance Notice. The shares
will be issued and sold to Yorkville at a per share price equal to 97% of the lowest daily volume weighted average price of Common
Stock for three consecutive trading days commencing on the trading day immediately following Yorkville’s receipt of an Advance
Notice. On September 30, 2024, pursuant to the SEPA, we paid Yorkville a structuring fee of $25,000 and a Commitment Fee by issuing
Yorkville 100,000 shares of Common Stock. Our right to sell shares to Yorkville under the SEPA was contingent upon us having an
effective registration statement, which was declared effective by the SEC on December 20, 2024. Refer to Liquidity and Capital
Resources - Significant Sources of Liquidity below for a further discussion of the SEPA.

Senior
Convertible Note

On
September 30, 2024, Yorkville advanced an initial $15.0 million (the “Pre-Paid Advance”) to us and we issued a
convertible promissory note (the “Senior Convertible Note”), with an interest rate of 8.00% and a maturity date of
September 30, 2025. Our obligations with respect to the Pre-Paid Advance and under the Senior Convertible Note are guaranteed by
Prairie LLC, a subsidiary of the Company, and Prairie Holdco, a subsidiary of the Company, pursuant to a global guaranty agreement
entered into by Prairie LLC and Prairie Holdco in favor of Yorkville on September 30, 2024. Yorkville may convert the Pre-Paid
Advance into shares of Common Stock at any time at the Conversion Price. We may, at any time, redeem all or a portion of the amounts
outstanding under the Senior Convertible Note at 105% of the principal amount thereof, plus accrued and unpaid interest.

In December 2024, and in conjunction with the
Credit Facility Agreement, we made a $3.7 million payment on the Senior Convertible Note, resulting in a principal balance of $11.3
million as of December 31, 2024. Additionally, in January and February 2025, Yorkville converted the remaining $11.3 million of the Senior
Convertible Note in exchange for 2.1 million shares of Common Stock. Refer to Liquidity and Capital Resources - Significant
Sources of Liquidity below for a further discussion of the Senior Convertible Note.

Subordinated
Promissory Note and Subordinated Note Warrants

On September 30, 2024, we entered into a subordinated promissory note (the
“Subordinated Note”) with First Idea Ventures LLC and The Hideaway Entertainment LLC (together, the “Noteholders”),
in a principal amount of $5.0 million, with a maturity of December 31, 2025. The Subordinated Note has an interest rate of 10.00% and
the Noteholders are entitled to a minimum return on capital of up to 2.0x upon the repayment, prepayment or acceleration of the obligations,
or the occurrence of certain other triggering events under the Subordinated Note. Pursuant to the terms of the Subordinated Note, we issued
to the Noteholders warrants (the “Subordinated Note Warrants”) to purchase up to 1,141,552 shares of Common Stock, vesting
in tranches based on the date of repayment of the Subordinated Note.

In
December 2024, and in conjunction with the Credit Facility Agreement, we made a $1.8 million payment on the Subordinated Note,
resulting in a principal balance of $3.2 million as of December 31, 2024. Refer to Liquidity and Capital Resources - Significant Sources of Liquidity below
for a further discussion of the Subordinated Note and Subordinated Note Warrants.

Factors
Affecting the Comparability of Financial Results

NRO
Acquisition

As
discussed above, on January 11, 2024, we entered into the NRO Agreement to acquire the Central Weld Assets, located in the DJ Basin in
Weld County, Colorado for total consideration of $94.5 million, subject to certain closing price adjustments and other customary closing
conditions. Pursuant to the NRO Agreement, we deposited $9.0 million of the Purchase Price into an escrow account on January 11, 2024.

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. Additionally on August 15, 2024, $6.0 million of the Deposit was released to NRO and the remaining $3.0 million was
returned to us.

On
October 1, 2024, we closed the NRO Acquisition and paid $49.6 million to the sellers in cash, using cash on hand, the proceeds from the
issuance of Common Stock, and a portion of the proceeds from the issuance of the Senior Convertible Note. We completed the final settlement
with NRO in December 2024, which resulted in a final purchase price of $55.5 million.

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Crypto
Sale

As previously discussed, we acquired our cryptocurrency mining operations
in May 2023, concurrent with the Merger. On January 23, 2024, we sold all of our Mining Equipment for consideration consisting of (i)
$1.0 million in cash and (ii) $1.0 million in deferred cash payments, to be paid out of (a) 20% of the monthly net revenues received by
the buyer 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 buyer associated with or otherwise attributable to the Mining Equipment
until the aggregate amount of such payments equals the Deferred Purchase Price, plus accrued interest. As of December 31, 2024, we have
received $0.3 million of the Deferred Purchase Price.

Commodity
Prices

Since
oil, natural gas, and NGL prices are the most significant factors impacting our results of operations, continued price variations can
have a material impact on our financial results and capital expenditures. In an effort to reduce the impact of price volatility, and
in compliance with requirements under our Credit Facility Agreement, 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. Refer to Results of Operations - Other income and expenses below for a discussion of our recognized gains or losses
on derivative contracts.

As
of December 31, 2024, we had the following outstanding crude oil and natural gas derivative contracts in place, which settle monthly
and are indexed to NYMEX West Texas Intermediate and NYMEX Henry Hub, respectively:

Results
of Operations

Revenue,
Production, and Average Realized Price

The
following table presents the components of our revenue, production, and average realized sales price for the periods indicated:

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Oil
revenue and production. For the year ended December 31, 2024, our oil production was 96.1 MBbls resulting in oil revenue of $6.6
million and an average realized price of $68.60 per barrel. All of our oil revenue for the year ended December 31, 2024 was derived from
the assets acquired in the NRO Acquisition, which closed on October 1, 2024. We did not have any oil revenue prior to the NRO Acquisition.

Natural
gas revenue and production. For the year ended December 31, 2024, our natural gas production was 245.1 MMcf resulting in natural
gas revenue of $0.6 million and an average realized price of $2.25 per MMcf. All of our natural gas revenue for the year ended December
31, 2024 was derived from the assets acquired in the NRO Acquisition, which closed on October 1, 2024. We did not have any natural gas
revenue prior to the NRO Acquisition.

NGL
revenue and production. For the year ended December 31, 2024, our NGL production was 33.0 MBbls resulting in NGL revenue of $0.8
million and an average realized price of $24.03 per MBbl. All of our NGL revenue for the year ended December 31, 2024 was derived from
the assets acquired in the NRO Acquisition, which closed on October 1, 2024. We did not have any NGL revenue prior to the NRO Acquisition.

Operating
expenses

The following table presents the components of our operating expenses for
the periods indicated:

NM: A per Boe calculation is not meaningful due
to a zero-value denominator.

Lease
operating expenses. For the year ended December 31, 2024, lease operating expenses (“LOE”)
increased $1.3 million compared to the year ended December 31, 2023, fully driven by LOE recognized for the properties acquired in the
NRO Acquisition, which closed on October 1, 2024.

Gathering, transportation, and processing expenses.
For the year ended December 31, 2024, gathering, transportation, and processing expenses increased $0.9 million compared to the year ended
December 31, 2023, fully driven by the gathering, transportation, and processing expenses recognized for the properties acquired in the
NRO Acquisition, which closed on October 1, 2024.

Ad
valorem and production taxes. For the year ended December 31, 2024, ad valorem and production taxes increased $0.6 million compared
to the year ended December 31, 2023, fully driven by the ad valorem and production taxes recognized for the properties acquired in the
NRO Acquisition, which closed on October 1, 2024.

Depreciation,
depletion, and amortization. For the year ended December 31, 2024, depreciation, depletion, and amortization (“DD&A”) expenses were $0.4 million, the majority of which related
to DD&A for the NRO Acquisition wells.

Exploration
expenses. For the year ended December 31, 2024, exploration expenses increased $0.5 million compared to the year ended December 31,
2023. These increases were driven by delay rental costs incurred on oil and gas leases during the year ended December 31, 2024, which
were not incurred during the same periods of 2023.

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General
and administrative expenses. For the year ended December 31, 2024, general and administrative expenses increased $14.3 million compared
to the year ended December 31, 2023. This increase aligns with the growth of our E&P business during the year ended December
31, 2024 and was primarily driven by incremental stock–based compensation of $5.7 million,
employee and benefit expenses of $4.0 million, legal and accounting costs of $2.4 million, financing commitment fees of $0.6 million,
investor relations costs of $0.4 million, and insurance and rent costs of $0.4 million.

Other expenses

The following table presents the components of our other expenses for the periods indicated:

Interest
expense. For the year ended December 31, 2024, interest expense increased $1.0 million
compared to the year ended December 31, 2023, primarily driven by the interest and premium paid for the partial
redemption of the Senior Convertible Note and the interest and premium paid for the partial redemption of the
Subordinated Note. Refer to Liquidity and Capital Resources - Significant Sources of Liquidity below for a further discussion of
the Senior Convertible Note and the Subordinated Note.

Loss
on derivatives, net. For the year ended December 31, 2024, we recognized a $4.4 million unrealized
loss, net on derivatives related to the change in fair value of our derivative contracts, which we entered into in December 2024 pursuant
to our Credit Facility Agreement. We did not have any outstanding derivative contracts during the year ended December 31, 2023, therefore,
we did not recognize a loss on derivatives for the period. Refer to Factors Affecting the Comparability of Financial Results –
Commodity Prices above for a further discussion of our derivative contracts.

Loss
on adjustment to fair value – debt and warrants. We have multiple financial instruments that are valued at fair value on a recurring basis; therefore, we recognize
the changes in fair value at each remeasurement period as a loss on adjustment to fair value – debt and warrants on our consolidated
statement of operations for the period. For the year ended December 31, 2024, the loss on adjustment to fair value – debt and warrants
reflects the fair value adjustments of $0.8 million for the SEPA, $2.1 million for the Senior Convertible Note, $1.1 million for the Subordinated
Note, and $1.4 million for the Subordinated Note Warrants recognized during the period. Refer to Liquidity and Capital Resources -
Significant Sources of Liquidity below for a further discussion of the SEPA, the Senior Convertible Note and the Subordinated Note.

For the year ended December 31, 2023, the loss
on adjustment to fair value – debt and warrants reflects the fair value adjustments of $39.8 million for the portion of the Series
D A Warrants, $3.8 million for the senior secured convertible debentures, which were converted into Common Stock in October 2023, and $1.5 million for the shares of Common Stock which we were obligated to issue as a result of
the Merger and related transactions, which were fully issued in September 2023.

Loss
on debt issuance. For the year ended December 31, 2024, the loss on debt issuance of $3.0 million reflects the loss recognized for
the issuance of the Subordinated Note and the Subordinated Note Warrants. As discussed above, we have elected the fair value option to
account for both the Subordinated Note and the Subordinated Note Warrants and engaged a third-party to determine the fair value of both
instruments at issuance. As of December 31, 2024, the total fair value of the Subordinated Note and the Subordinated Note Warrants exceeded
the proceeds of $5.0 million, as a result, we have recognized a loss on debt issuance of $3.0 million on our consolidated statements
of operations for the year ended December 31, 2024.

Interest income and other. For the year ended
December 31, 2024, interest income and other increased $0.3 million compared to the year ended December 31, 2023, primarily driven by
higher average cash balances in the current period.

Liquidated
damages. For the year ended December 31, 2023, we recognized liquidated damages expense of $0.5 million due to the registration statement
registering the resale of certain shares of our Common Stock and the shares of Common Stock underlying the Series D Preferred Stock and
Series D PIPE Warrants not being declared effective within the timeframe required under the related registration rights agreement. We
did not recognize any liquidated damage expense during the year ended December 31, 2024.

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Discontinued
operations

The following table presents the components of our net loss from discontinued
operations for the periods indicated:

For
the year ended December 31, 2024, the net loss from discontinued operations decreased $16.0 million compared to the year ended
December 31, 2023. As discussed above, we completed the Crypto Sale in January 2024; therefore, we did not have any cryptocurrency
mining revenue or related expenses during the majority of the year ended December 31, 2024. However, we did recognize a $1.1 million
loss on the sale of cryptocurrency mining equipment. Additionally, during the year ended December 31, 2023, we recognized $17.1
million of impairment of cryptocurrency mining equipment to write off the excess of the allocated purchase price to the
cryptocurrency assets which were over the fair value of the acquired net assets and to subsequently write off shipping and customs
fees incurred on miners after the Merger. Refer to Factors Affecting the Comparability of Financial Results – Crypto Sale above for a further
discussion of the Crypto Sale.

Non-GAAP
Financial Measures

Adjusted
EBITDA and PV-10 are financial measures not calculated or presented in accordance with generally accepted accounting principles (“GAAP”).
These supplemental non-GAAP financial measures are used by management and external users of our financial statements, such as investors,
lenders, and rating agencies and may not be comparable to similarly-titled measures reported by other companies.

Adjusted
EBITDA

Adjusted EBITDA is used by management to evaluate the performance of our
business, make operational decisions, and assess our ability to generate cashflows. Management believes Adjusted EBITDA provides investors
with helpful information to better understand the underlying performance trends of our business, facilitate period-to-period comparisons,
and assess the company’s operating results.

Adjusted EBITDA is derived from net loss from
continuing operations and is adjusted for income tax expense, depreciation, depletion, and amortization, accretion of asset
retirement obligations, non-cash stock-based compensation, interest expense (income), net, non-cash loss on issuance of debt,
non-cash loss on adjustment to fair value – debt and warrants, and loss on unrealized derivatives, all as applicable. We
adjust net loss from continuing operations for the items listed above to arrive at Adjusted EBITDA because these amounts can vary
substantially between periods and companies within our industry depending upon accounting methods, book values of assets, capital
structures, and the method by which assets were acquired. Adjusted EBITDA has limitations as an analytical tool, including that it
excludes certain items that affect our reported financial results. Adjusted EBITDA should not be considered as an alternative to, or
more meaningful than, net income calculated in accordance with GAAP or as an indicator of our operating performance or liquidity.
Additionally, our calculation of Adjusted EBITDA may not be comparable to similarly titled measures used by other companies.

The
following table presents the reconciliation of Net loss from continuing operations to Adjusted EBITDA for the periods
indicated:

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PV-10

PV-10 is a financial measure not presented in accordance
with U.S. GAAP. PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure for proved
reserves. PV-10 is a computation of the Standardized Measure on a pre-tax basis and is equal to the Standardized Measure at the applicable
date, before deducting future income taxes discounted at 10%. Neither PV-10 nor Standardized Measure represents an estimate of the fair
market value of the applicable crude oil, natural gas, and NGLs properties.

We believe that the presentation of PV-10 is
relevant and useful to our investors as a supplemental disclosure to the Standardized Measure, or after-tax amount, because it
presents the discounted future net cash flows attributable to our reserves before considering future corporate income taxes and our
current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on
prices and discount factors that are consistent for all companies.

The
following table presents the reconciliation of the Standardized Measure to the PV-10 of our estimated proved reserves for the periods
indicated:

Liquidity
and Capital Resources

Overview

Our
E&P activities will require us to make significant operating and capital expenditures. In 2023, our primary sources of liquidity
were the proceeds from the Series D PIPE and the Series E PIPE, which funded the purchase of the initial Genesis Assets and working
capital, as well as proceeds from the exercise of warrants, which funded, among other things, working capital and the deposit for
the NRO Acquisition in 2024. We commenced drilling wells on our Genesis Bolt-on Assets in the third quarter of 2024 and those wells
began producing in February 2025.

Additionally,
during the third quarter of 2024, we raised approximately $35.0 million in cash by issuing Common Stock, the Senior Convertible
Note, and the Subordinated Note. On October 1, 2024, we used 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 to fund the closing of the NRO Acquisition. On December 16,
2024, we entered into a reserve-based Credit Facility with Citi and borrowed $28.0 million to help fund our working capital needs.
Management expects that our cash balance, expected revenues from the producing NRO wells and newly producing Shelduck wells, and
liquidity available under the SEPA and Credit Facility and potential offerings under the effective Form S-3 registration statement
will be sufficient to fund our development program and operations.

Our
development program is dependent upon our cash flow from operations generated from our assets and
our ability to obtain additional financing through our SEPA and Credit Facility. Additionally, we could obtain additional financing through public and private capital markets; however,
the availability of additional capital would be subject to numerous factors
outside of our control including prices of oil and natural gas and the overall health of the U.S. and global economic environments.
There can be no assurance that we will be able to obtain such additional capital. The amount and allocation of future capital
expenditures will depend upon a number of factors, including the amount and timing of cash flows from operations, investing and
financing activities, and the timing and cost of additional capital sources.

We
currently plan to be the operator on substantially all of our acreage. As a result, we anticipate that the timing and level of our capital spending
will largely be discretionary and within our control. We could choose to defer a portion of our planned capital expenditures depending
on a variety of factors, including, but not limited to, the receipt and timing of required regulatory permits and approvals, seasonal
conditions, drilling and acquisition costs, the level of participation by other working interest owners, the success of our drilling
activities, prevailing and anticipated prices for oil, natural gas, and NGLs, the availability of necessary equipment, infrastructure
and capital.

Working
Capital

We
define working capital as current assets less current liabilities. As of December 31, 2024, we had a working capital deficit of
$44.7 million and cash and cash equivalents of $5.2 million and as of December 31, 2023, we had working capital of $8.1 million and cash
and cash equivalents of $13.0 million.

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Cash
Flows from Operating, Investing, and Financing Activities

The
following table summarizes our cash flows for the years indicated:

Operating
activities. Net cash used in operating activities totaled $9.3 million and $11.9 million during the years ended December 31, 2024
and 2023, respectively. The $2.6 million change in our net cash used in operating activities was largely due to an increase in revenue
recognized during the current period, partially offset by increased operating costs during the current period.

Investing
activities. Net cash used in investing activities totaled $83.4 million and $23.7
million during the years ended December 31, 2024 and 2023, respectively. The $59.7 million increase in our net cash used in investing
activities was largely driven by the NRO Acquisition, with a final purchase price of $55.5 million, and a $28.3 million increase in capital investments in oil and natural
gas properties during the year ended December 31, 2024. These increases were partially offset by the $21.2 million invested in connection
with the Exok Option Purchase during the year ended December 31, 2023.

Financing
activities. Net cash provided by financing activities totaled $84.9 million for the year ended December 31, 2024, driven by proceeds
of $33.5 million from the exercise of Series D B and Series E B Warrants, $28.0 million from borrowings under the Credit Facility, net
of related issuance costs of $0.3 million, $15.0 million of proceeds from the issuance of Common Stock, net of related issuance costs
of $5.0 million, $14.3 million of proceeds from the issuance of the Senior Convertible Note, partially offset by a repayment of $3.8 million,
and $5.0 million of proceeds from the issuance of the Subordinated Note, partially offset by a repayment of $1.8 million. Net cash provided
by financing activities totaled $48.6 million for the year ended December 31, 2023, which was comprised of proceeds from the issuance
of the Series D PIPE of $17.4 million, net of related financing costs of $0.9 million, the issuance of the Series E PIPE of $20.0 million,
net of related financing costs of $0.2 million, and proceeds of $12.5 million from the exercise of Series D B Warrants.

Significant
Sources of Liquidity

Credit
Facility. On December 16, 2024, we, as borrower, entered into the Credit Facility Agreement with Citi, as administrative agent
and the financial institution party, which has a maximum credit commitment of $1.0 billion and is set to mature on December 16,
2026. The Credit Facility is guaranteed by all of our restricted subsidiaries and is secured by a first-priority security interest
on substantially all of our oil and natural gas properties and substantially all of our personal property assets, subject to
customary exceptions. The borrowing base is subject to semi-annual redeterminations based upon
the value of our oil and gas properties as determined in a reserve report dated as of January and July of each year, subject to certain
interim redeterminations.

We are subject to certain financial covenants
and customary restrictive covenants under the Credit Facility. The financial covenants require us to maintain, for each fiscal
quarter commencing with the fiscal quarter ending March 31, 2025, a Net Leverage Ratio (as defined in the Credit Facility Agreement)
of no greater than 2.50 to 1.00 and a Current Ratio (as defined in the Credit Facility Agreement) of at least 1.00 to 1.00.

As of December 31, 2024, the Credit Facility had a borrowing base and an
aggregate elected commitment of $44.0 million and a $5.0 million sublimit for the issuance of letters of credit. As of December 31, 2024,
we had $28.0 million of revolving borrowings and no letters of credit outstanding under the Credit Facility, resulting in $7.2 million
of availability for future borrowings and letters of credit. On February 3, 2025, we entered into the First Amendment to the Credit Facility Agreement, which, among other things, increased the borrowing base and the aggregate elected commitments to $60.0 million.

65

Standby
Equity Purchase Agreement. On September 30, 2024, we entered into the SEPA with Yorkville, whereby, subject to certain conditions,
we have the right, not the obligation, to sell to Yorkville up to $40.0 million shares of Common Stock, at any time and in an amount
as specified in the applicable Advance Notice, during the commitment period commencing on the SEPA Effective Date and terminating on
September 30, 2026. Each Advance by us under the SEPA is subject to a maximum limit equal to 100% of the aggregate volume traded of our
Common Stock on the Nasdaq Stock Market during the five trading days immediately prior to the date of the Advance Notice. The shares
will be issued and sold to Yorkville at a per share price equal to 97% of the lowest daily volume weighted average price of Common Stock
for three consecutive trading days commencing on the trading day immediately following the Yorkville’s receipt of an Advance Notice.
On September 30, 2024, pursuant to the SEPA, we paid Yorkville a structuring fee of $25,000 and a Commitment Fee by issuing Yorkville
100,000 shares of Common Stock.

Our right to sell shares to Yorkville under the SEPA was contingent upon
us having an effective registration statement, which was declared effective by the SEC on December 20, 2024. Pursuant
to the SEPA, we may issue up to a total of 4,198,343 shares of Common Stock within the cap of 19.99% of our issued and outstanding Common Stock as of the SEPA
Effective Date through Advances under the SEPA,
upon conversion of the Senior Convertible Note or through any other issuances of Common Stock thereunder. However, per the SEPA, we do not have access to issue an Advance Notice until the Pre-Paid Advance of $15.0 million
(the Senior Convertible Note) is fully repaid. In December 2024, and in conjunction with the Credit Facility Agreement,
we made a $3.7 million payment on the Senior Convertible Note, resulting in a principal balance of $11.3 million as of December 31, 2024.
Additionally, in January and February 2025, Yorkville converted the remaining $11.3 million of the Senior Convertible Note in exchange
for 2.1 million shares of Common Stock.

We
have determined that the SEPA represents a derivative instrument pursuant to ASC 815, which should be recorded at fair value at
inception and remeasured at fair value each reporting period with changes in the fair value recognized in earnings. Additionally,
the Commitment Fees and any issuance costs associated with the SEPA have been expensed to general and administrative expenses. As
such, we have recorded the SEPA at its fair value of $0.8 million as of December 31, 2024 and recorded the corresponding $0.8
million loss on adjustment to fair value – debt and warrants for the year ended December 31, 2024.

Senior
Convertible Note. On September 30, 2024, Yorkville advanced the Pre-Paid Advance of $15.0
million to us and we issued the Senior Convertible Note, with an interest rate of 8.00% and a maturity date of September 30, 2025. Yorkville
may convert the Pre-Paid Advance into shares of Common Stock at any time at the Conversion Price. We may, at any time, redeem all or a
portion of the amounts outstanding under the Senior Convertible Note at 105% of the principal amount thereof, plus accrued and unpaid
interest. Additionally, we may also convert the Pre-Paid Advance into shares of Common Stock at any time at the Conversion Price, however,
a conversion requested by us would not result in us receiving cash but instead would be applied towards reducing the outstanding balance
of the Senior Convertible Note.

In December 2024, and in conjunction with the Credit Facility Agreement,
we made a $3.7 million payment on the Senior Convertible Note, resulting in a principal balance of $11.3 million as of December 31, 2024.
Additionally, in January and February 2025, Yorkville converted the remaining $11.3 million of the Senior Convertible Note in exchange
for 2.1 million shares of Common Stock.

We have determined that certain features of the Senior Convertible Note
require bifurcation and separate accounting as embedded derivatives and have elected the fair value option to account for the Senior Convertible
Note; therefore, in accordance with ASC 815, we have recorded the Senior Convertible Note at fair value. As of December 31, 2024, the
fair value of the Senior Convertible Note was $12.6 million, which resulted in a loss on adjustment to fair value – debt and warrants
of $2.1 million for the year ended December 31, 2024.

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Subordinated
Promissory Note and Subordinated Note Warrants. On September 30, 2024, we entered into the Subordinated Note with the Noteholders,
First Idea Ventures LLC and The Hideaway Entertainment LLC, in a principal amount of $5.0 million, with a maturity of December 31, 2025.
The Noteholders are entities controlled by Jonathan H. Gray, who is a director of the Company, therefore the Subordinated Note and Subordinated
Note Warrants are presented as related-party on our consolidated balance sheet as of December 31, 2024. The Subordinated Note has an interest
rate of 10.00% and the Noteholders are entitled to a minimum return on capital of up to 2.0x upon the repayment, prepayment or acceleration
of the obligations, or the occurrence of certain other triggering events under the Subordinated Note. In December 2024, and in conjunction with the Credit Facility Agreement,
we made a $1.8 million payment on the Subordinated Note, resulting in a principal balance of $3.2 million as of December 31, 2024.

Pursuant to the terms of the Subordinated Note,
we issued the Subordinated Note Warrants to purchase up to 1,141,552 shares of Common Stock to the Noteholders, vesting in tranches based
on the date of repayment of the Subordinated Note. As of December 31, 2024, Subordinated Note Warrants providing the right to purchase
570,778 shares of Common Stock had vested and were outstanding.

We have determined that certain features of the Subordinated Note require
bifurcation and separate accounting as embedded derivatives and have elected the fair value option to account for the Subordinated Note;
therefore, in accordance with ASC 815, we have recorded the Subordinated Note at fair value and will remeasure the fair value each reporting
period with changes in fair value recognized in earnings. As of December 31, 2024, the fair value of the Subordinated Note is $4.6 million,
which resulted in a loss on adjustment to fair value – debt and warrants of $1.1 million for the year ended December 31, 2024.

Liquidity
Analysis

For
the year ended December 31, 2024, we had a net loss of $40.9 million. We cannot predict if or when we will be profitable, and we may continue to incur losses for an indeterminate
period of time. Additionally, we may be unable to achieve or sustain profitability on a quarterly or annual basis and extended periods
of losses and negative cash flow may prevent us from successfully operating and expanding our business. As of December 31, 2024, we had
cash and cash equivalents of $5.2 million, a working capital deficit of $44.7 million, and an accumulated deficit of $119.8 million.

The
assessment of liquidity requires management to make estimates of future activity and judgments about whether we can meet our
obligations, have adequate liquidity to operate, and maintain compliance with the applicable financial covenants of our Credit
Facility Agreement, as discussed above. Significant assumptions used in our forecasted model of liquidity in the next 12 months
include our current cash position and our ability to manage spending. Based on an assessment of these factors, management expects
that our cash balance, expected revenues from our existing producing wells and newly producing Shelduck wells, and liquidity
available under the SEPA and Credit Facility and potential offerings under the effective Form S-3 registration statement will be
sufficient to meet our obligations over the next 12 months and fulfil the financial covenant requirements under our Credit Facility
Agreement, as discussed above.

Since
entering into the SEPA in September 2024 and the Credit Facility Agreement in December 2024 and with the Form S-3 registration
statement becoming effective in December 2024, we have the ability to access funds to meet our working capital needs. Since our
ability to request an Advance under the SEPA does not require action on the part of management, other than requesting the Advance,
and the maximum Advance amount is less or equal to our liquidity needs, substantial doubt about our ability to continue as a going
concern does not exist.

Critical
Accounting Policies and Estimates

The
discussion and analysis of our financial condition and results of operations is based upon the accompanying consolidated financial
statements. These financial statements have been prepared in conformity with GAAP, which requires management to make estimates and
assumptions that affect the amounts reports for assets, liabilities, revenues, and expenses and the disclosure of contingent assets
and liabilities. Management believes its estimates and assumptions to be reasonable under these circumstances. Certain estimates and
assumptions are inherently unpredictable and actual results could differ from those estimates. Described below are the most
significant policies and the related estimates and assumptions used by management in the preparation of our financial statements.
Refer to Item 8. Financial Statements and Supplementary Data – Note 2 – Summary of Significant Accounting Policies for
a further discussion of our accounting policies.

Oil,
Natural Gas, and NGL Reserves and the Standardized Measure of Discounted Net Future Cash Flows

Our
proved oil, natural gas, and NGL reserve estimates as of December 31, 2024 and associated future net cash flows included in this Annual
Report have been prepared by CG&A, independent third-party reserve engineers, in accordance with the rules and regulations of the
SEC in Regulation S-X, Rule 4-10.

Reserve
engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in
an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological
interpretation. To achieve reasonable certainty, our internal reserve engineers and CG&A employed technologies that have been demonstrated
to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves
include, but are not limited to, technical and economic data including well logs, geologic maps, seismic data, well test data, production
data, historical price and cost information, and property ownership interests. Estimates of economically recoverable oil and natural
gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including
geologic interpretation, prices and future production rates and costs. Periodic revisions to the estimated reserves and future cash flows
may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil, natural gas, and NGL prices,
changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates
may differ significantly from the quantities of oil and natural gas ultimately recovered.

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The
Standardized Measure is the present value, discounted at 10%, of estimated future net cash flows to be generated from the production
of proved reserves calculated by using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month
in the period January through December (with consideration of price changes only to the extent provided by contractual arrangements).
The estimated future net cash flows are reduced by projected future development, production (excluding DD&A and any impairments of
oil and natural gas properties), plug and abandon (“P&A”) costs, and estimated future income tax expenses. The Standardized Measure is calculated per
ASC Topic 932, Extractive Activities - Oil and Gas and in accordance with SEC pricing guidelines.

Although
our estimates of total proved reserves, development costs, and production rates were based on the best available information, the development
and production of the oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production
quantities may vary significantly from our estimates. Therefore, the Standardized Measure should not be considered to represent our estimate
of expected revenues or the fair value of our proved oil, natural gas, and NGL reserves.

As
discussed further below, our estimates of proved reserves materially impact calculated depletion expense each period; therefore, if our
estimates of total proved reserves decrease, the rate at which we record depletion expense will increase, reducing earnings.

Oil
and Natural Gas Properties

We
follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs such
as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals, and exploration overhead are expensed
as incurred. All costs related to production, general corporate overhead, and similar activities are also expensed as incurred. All property
acquisition costs and development costs are capitalized when incurred.

In
successful efforts accounting, exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved
reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. If proved reserves
are not found, the costs related to unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that
cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if
there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing
the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development
activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may
take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves,
including the costs of all development wells and related equipment used in the production of natural gas and oil, are capitalized.

The
costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are
depreciated using the UOP method based on total estimated proved developed oil and natural gas reserves. Costs for wells in the process
of being drilled, significant nonproducing properties, and in-process development projects are excluded from depletion until the related
project is completed and proved producing reserves are established or, if unsuccessful, abandonments expense is recognized. The costs
of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP
method based on total estimated proved developed and undeveloped reserves.

Proceeds
from the sales of individual oil and natural gas properties and the capitalized costs of individual properties sold or abandoned are
credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the
depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However,
a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially
impact the depletion rate of the remaining properties in the amortization base.

When
circumstances indicate that the carrying value of proved oil and natural gas properties may not be recoverable, we compare unamortized
capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which
identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based
on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant
data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated
using the income approach described in ASC 820. If applicable, we utilize prices and other relevant information generated by market transactions
involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value.
The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments
of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and
estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future
cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital.

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Derivative
Instruments

We
utilize commodity derivative instruments to reduce our exposure to crude oil and natural gas price volatility for a portion of our estimated
production from its proved, developed, producing oil and natural gas properties. The fair values of our derivative instruments are measured
on a recurring basis using a third-party industry-standard pricing model.

We
have not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses
resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds
or payments related to the early termination of derivative contracts during the period are recognized as net gain or loss on derivatives,
as applicable, in the consolidated statements of operations.

Asset
Retirement Obligations

Our
oil and natural gas properties include estimates of future expenditures to P&A wells, pipelines, platforms, and other related facilities
after the reserves have been depleted. We recognize the present value of the asset retirement obligation costs as a liability when it
is incurred or assumed (acquired) and an increase to its capitalized oil and natural gas properties. The capitalized asset retirement
obligation costs are depleted over the productive lives of the oil and natural gas properties while the asset retirement obligation liability
is accreted to the expected settlement value over the productive lives of the oil and natural gas properties. Upon settlement, the difference
between the recorded liability amount and the amount of costs incurred will be recognized as an adjustment to the capitalized cost of
oil and natural gas properties.

The
determination of future asset retirement obligations requires estimates of the future costs of removal and restoration, productive lives
of the oil and natural gas properties based on reserve estimates, and future inflation rates. Estimated costs consider historical experience,
third-party estimates, and government regulatory requirements but do not consider salvage values. These costs could be subject to revisions
in subsequent years due to changes in regulatory requirements, the estimated P&A cost, and the estimated timing of the oil and natural
gas property retirement. In subsequent periods, if the estimate of the asset retirement obligation liability changes, we record an adjustment
to both the asset retirement obligation liability and the oil and natural gas property carrying value. Additionally, we estimate the
credit-risk adjusted discount rate, which is applied to the future inflated P&A costs to determine the discounted present value which
is recognized as the initial liability. The determined credit-risk adjusted discount rate is also subsequently applied to accrete the
liability.

Commitments
and Contingencies

We
recognize a liability for loss contingencies when we believe it is probable a liability has been incurred, and the amount can be reasonably
estimated. If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range,
we accrue that amount. When no amount within the range is a better estimate than any other amount we accrue the minimum amount in the
range.

Liabilities
at Fair Value

On September 30, 2024, we entered into the SEPA and issued the Senior Convertible
Note, the Subordinated Note, and the Subordinated Note Warrants. All three of these agreements contain features which must be evaluated
for embedded derivatives and bifurcation pursuant to ASC 815. As such, we have elected to account for the SEPA, the Senior Convertible
Note, the Subordinated Note, and the Subordinated Note Warrants using the fair value option.

Stock-based
Compensation

Our
stock–based compensation awards are classified as either equity or liability awards in accordance with GAAP. The fair value of
an equity–classified award is determined at the grant date and is amortized to general and administrative expense on a graded attribution
basis over the vesting period of the award. The fair value of a liability–classified award is determined on a quarterly basis beginning
at the grant date until final vesting. Changes in the fair value of liability–classified awards are recorded to general and administrative
expense over the vesting period of the award.

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Additionally,
we grant PSUs, which vest and become earned upon the achievement of certain performance goals based on our relative total shareholder
return as compared to the performance peer group during the performance period, which represents a market condition per ASC Topic
718, Compensation—Stock Compensation. As such, the fair value of the PSUs awards is determined by a third party using a Monte
Carlo simulation model as of the grant date. Per the PSU agreements, these awards can be settled in either stock or cash, as determined
by the Committee; however, unless the Committee determines otherwise, these PSUs will be settled in stock; therefore, we classified the
PSUs as equity awards.

We
recognize compensation expense related to equity–classified and liability–classified awards using the straight-line method
over the requisite service period during which the employee, board member, director, or advisor is required to provide services in exchange
for the award in accordance with ASC Topic 718, Compensation - Stock Compensation. We have elected to not estimate the forfeiture
rate of its RSUs and PSUs in its initial calculation of compensation expense, but instead we will adjust compensation expense for forfeitures
as they occur.

Income
Taxes

We
account for income taxes using the asset and liability method whereby deferred tax assets are recognized for deductible temporary
differences, and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the
differences between the reported amounts of assets and liabilities and their respective tax basis. Deferred tax assets are reduced
by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax
assets will be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the
date of enactment. As of December 31, 2024, we had a full valuation allowance to offset its net deferred tax
assets.

Off–Balance
Sheet Arrangements

We
do not have any off–balance sheet arrangements.

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