What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-03-31 compared with 2025-03-31 · 133 added, 76 removed, 177 unchanged (54% of the section changed)

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See “ Risk Factors ” and “ Forward-Looking Statements .

The discussion in this section has been impacted by the restatement described in the Explanatory Note at the beginning of this Annual Report on Form 10-K and in Note 4 of the consolidated financial statements.

Certain of the financial and other information provided in this Management’s Discussion and Analysis of our financial condition and results of operations has been updated to reflect the restatement adjustments.

Summary of The Information Contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations

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In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies.

Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico and in the Denver-Julesberg Basin in Colorado and Wyoming.

As of December 31, 2024, we held approximately 14,105 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, PEDCO, and which are operated by our wholly-owned operating subsidiary, RAZO, which asset we refer to as our “ Permian Basin Asset .” Also as of December 31, 2024, we held approximately 14,809 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and 3,860 net D-J Basin acres located in Laramie County, Wyoming, through our wholly-owned subsidiary, PRH, and which are operated by our wholly-owned operating subsidiary, Red Hawk, which asset we refer to as our “ D-J Basin Asset .” As of December 31, 2024, we held interests in 35 gross (33.5 net) wells in our Permian Basin Asset, of which 28 gross (26.5 net) wells are active producers, five gross (five net) wells are inactive, and two gross (two net) wells are active salt water disposal wells (“ SWD’ s”), all of which are held by PEDCO and operated by RAZO, and interests in 82 gross (21.9 net) wells in our D-J Basin Asset held by PRH, all of which 17 gross (15.4 net) wells are operated by Red Hawk and currently producing, 48 gross (6.5 net) wells are non-operated, and 17 wells have an after-payout interest.

Detailed information about our business plans and operations, including our core D-J Basin and Permian Basin Assets, is contained under “ Part 1 ” — “ Item 1.

Our current properties are located in the Denver-Julesberg Basin (D-J Basin) in Colorado and Wyoming, and the Powder River Basin (PRB) in Wyoming, and in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (Permian Basin).

As of December 31, 2025, we held approximately 99,561 net acres in the D-J Basin located in Weld and Morgan Counties, Colorado and Laramie County, Wyoming, through our wholly-owned subsidiaries, PRH Holdings LLC (PRH) and North Peak Oil & Gas, LLC (NPOG) (the D-J Basin Asset), which assets are operated by the Company’s wholly-owned operating subsidiaries, Red Hawk Petroleum, LLC (Red Hawk), North Silo Resources, LLC (NSR), and Longs Peak Resources, LLC (LPR).

On April 3, 2025, effective January 1, 2025, the Company sold all of its legacy 17 gross (15.4 net) operated wells in the D-J Basin in order to reduce plugging and abandonment liabilities and recurring operating expenses.

The Company retained ownership of the associated leasehold interests, as these legacy wells no longer provided meaningful oil and gas production.

As of December 31, 2025, the Company held approximately 201,886 net acres in the Powder River Basin, predominantly located in Laramie and Campbell Counties, Wyoming, through its wholly-owned subsidiary Century Oil and Gas, LLC (COG).

These assets are operated by the Company’s wholly-owned operating subsidiaries, COG, Navigation Powder River, LLC ( NPR ), and Pine Haven Resources, LLC (“ Pine Haven ”), and are referred to as the “Powder River Basin Asset” or the “PRB Asset.”

As of December 31, 2025, we held approximately 14,105 net acres in the Permian Basin located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, Pacific Energy Development Corp.

These assets are operated by our wholly-owned operating subsidiary, Ridgeway Arizona Oil Corp.

( RAZO ), and are collectively referred to as our “Permian Basin Asset.”

As of December 31, 2025, we held interests in 184 gross (79.4 net) wells, consisting of 170 producing wells, three saltwater disposal wells, and 11 drilled but uncompleted wells (“ DUCs ”) in the D-J Basin Asset.

Of these wells, 74 gross (66.9 net) were operated and 110 gross (12.5 net) were non-operated.

In the PRB Asset, we held interests in 156 gross (135.4 net) wells, consisting of 140 producing wells, 15 injection wells, and one saltwater disposal well.

Of these wells, 16 gross (1.4 net) were non-operated.

In the Permian Basin, we held interests in 38 gross (34.5 net) wells in, consisting of 34 producing wells, two injection wells, and two saltwater disposal wells.

Detailed information about our business plans and operations, including our core D-J Basin, Powder River Basin, and Permian Basin Assets, is contained under “ Part 1 ” — “ Item 1.

Business ” above.

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Our estimated net proved crude oil and natural gas reserves at December 31, 2025 and 2024 were approximately 32.1 million barrels of oil equivalent (“ MMBoe ”) and 18.1 MMBoe, respectively.

The 1.1 MMBoe increase was primarily due to the addition of proved undeveloped reserves in our D-J Basin Asset as a result of increased activity around our acreage and favorable pricing.

The 14.0 MMBoe increase was primarily due to increase in proved developed producing reserves related to the acquisition of properties in the D-J and Powder River Basin, and proved undeveloped reserves related to the acquisition of properties in the D-J Basin.

Using the average monthly crude oil price of $65.34 per barrel (“ Bbl ”) and natural gas price of $3.39 per thousand cubic feet (“ Mcf ”) for the twelve months ended December 31, 2025, our estimated discounted future net cash flow (“ PV-10 ”) for our proved reserves was approximately $357.7 million, of which approximately $100.2 million are proved undeveloped reserves.

Total reserve value at December 31, 2024, represents a decrease of approximately $52.8 million or 23% from approximately $231.7 million a year earlier using the same SEC pricing and reserves methodology.

The decrease is primarily attributable to commodity pricing, as the average SEC pricing for 2024, noted above, was lower than the 2023 average pricing of $78.22 per Bbl for crude oil and $2.64 per Mcf for natural gas.

Total reserve value at December 31, 2025, represents an increase of approximately $178.8 million or 100% from approximately $178.9 million a year earlier using the same SEC pricing and reserves methodology.

The increase is primarily attributable to the increase in proved reserves volumes related to the related to the acquisition of properties in the D-J Basin and Powder River Basin from the Mergers.

The reserves as of December 31, 2025 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc.

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During the year ended December 31, 2025, our net crude oil, natural gas, and NGLs sales volumes increased to 910,068 Bbls, or 2,494 barrels of oil per day (“ Bopd ”), from 671,796 Bbls, or 1,835 Bopd, a 36% increase over the previous fiscal year.

The increase in production volume is related to our participation in 24 new non-operated wells (11 of which occurred in the latter four months of 2024) in the D-J Basin and the drilling and completion of three operated wells with a third-party in the Permian Basin in the latter part of Q1 2024 (see additional detail below).

The rise in production volume is largely driven by our October 2025 Mergers, resulting in an additional 303 Mboe of production during November and December 2025 combined (see further details below).

Significant Capital Expenditures

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Mineral Acquisitions

Merger Acquisition

Drilling and Facilities

*see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”.

Financial Statements and Supplementary Data ” - “ Note 6 – Merger Acquisition and Note 7 - Oil and Gas Properties ”.

Market Conditions and Commodity Prices

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Financial Statements and Supplementary Data ”).

We reported net income for the year ended December 31, 2024 of $17.8 million, or $0.20 per share, compared to net income for the year ended December 31, 2023 of $1.7 million or $0.02 per share.

The increase in net income of $16.1 million was primarily due to a recognition of an income tax benefit of $12.8 million (see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 14 – Income Taxes ”) coupled with $8.8 million increase in revenue in the current period and a $4.3 million loss on the Milnesand Sale in the prior period, offset by a $9.5 million increase in total operating expenses in the current period, offset further by a $0.2 million decrease in other income and a $0.1 million loss on sale of oil and gas properties in the current period (all of which are discussed in more detail below).

References to the “ current period ” mean the year ended December 31, 2025, whereas references to the “ prior period ” mean the year ended December 31, 2024.

Net (Loss) Income

We reported a net loss for the year ended December 31, 2025 of $10.4 million, or ($2.25) per share, compared to net income for the year ended December 31, 2024 of $12.3 million or $2.76 per share.

The decrease in net income of $22.7 million was primarily due to our October 2025 Mergers, whereby all operating expenses increased, and we incurred interest expense on our A&R Credit Agreement (for which we drew down on for the first time in October 2025) offset by a gain on derivative contracts which were novated to us on upon closing of the Mergers.

Additional decreases were due to the recognition of $1.4 million from a note receivable – credit loss related to the full write-off of the Tilloo Note receivable, corresponding accrued interest and posting closing adjustments owed to the Company related to the sale of our EOR Operating Company in November 2023, and a $0.9 million impairment to oil and gas properties, offset by a net $2.6 million gain on sale on oil and gas properties when comparing periods (each discussed in more detail below) and an income tax expense of $8.1 million (see in the notes to the consolidated financial statements under “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 17 – Income Taxes ”).

The following table sets forth the revenue and production data for the years ended December 31, 2025 and 2024:

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Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil.

Total crude oil, natural gas and NGL revenues for the year ended December 31, 2024, increased $8.8 million, or 28%, to $39.6 million, compared to $30.8 million for the same period a year ago, due to a favorable volume variance of $8.8 million.

There was a negligible price variance over the periods.

The increase in production volume is related to our participation in 24 new non-operated wells in the D-J Basin and the drilling and completion of three operated wells in the Permian Basin.

Total crude oil, natural gas and NGL revenues for the year ended December 31, 2025, increased $6.2 million, or 16%, to $45.8 million, compared to $39.6 million for the same period a year ago, due to a favorable volume variance of $12.2 million, offset by an unfavorable price variance of $6.0 million, due primarily to the average sales price for crude oil realized by the Company decreasing compared to the year ended December 31, 2024.

The increase in production volume is related to our October 2025 Mergers whereby we added a total 303 Mboe of oil and gas production sales for the months of November and December 2025 combined.

Net Operating and Other (Income) Expenses

The following table sets forth operating and other expenses for the years ended December 31, 2025 and 2024 (in thousands):

Increase (Decrease)

% Increase (Decrease)

(As Restated)

Direct Lease Operating Expense

Loss on settlement of ARO

Lease Operating Expenses

Direct Lease Operating Expenses

Total Lease Operating Expenses

Depreciation, Depletion,

Amortization and Accretion

Impairment of Oil and Gas Properties

General and Administrative (Cash)

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Total General and Administrative Expense

Loss on Sale of Oil and Gas Properties

Gain (Loss) on Sale of Oil and Gas Properties, net

Gain on Sale of Fixed Asset

Note Receivable – Credit Loss

Net gain on derivative contracts

Interest Expense

Interest Income

Other Income (Expense)

Gain on Sale of Fixed Asset

*Includes severance, ad valorem taxes, workover adjustments and assessment and marketing costs.

* Includes severance, ad valorem taxes, assessment and gathering, transportation and processing costs.

Lease Operating Expenses.

The increase of $2.6 million was primarily due to higher direct and variable lease operating expenses associated with the higher oil volume resulting from the increased number of wells and increased oil and gas production during the current year’s period, compared to the prior year’s period.

Lease operating expenses increased by $6.7 million for the year ended December 31, 2025, primarily as a result of the October 2025 Mergers.

The acquired properties contributed $4.4 million of direct lease operating expenses, $0.3 million of workover expenses, and $2.9 million of other operating costs, during the two-month period ended December 31, 2025, offset by $0.9 million in lower direct and variable lease operating expenses associated with lower pre-merger production volumes.

Depreciation, Depletion, Amortization and Accretion.

The $5.9 million increase was primarily the result of an increase in production (noted above) in the current period when compared to the prior period.

Additionally, the Company continued to adhere to its plugging and abandonment program in the Permian Basin Asset (in accordance with the terms of an existing compliance order) to plug additional wells over the next several years, which increased accretion expense in Q4 2024 by approximately $0.4 million.

Increased by $2.1 million for the year ended December 31, 2025, compared to the prior period, primarily due to the production increase noted above.

Impairment of Oil and Gas Properties.

The Company recorded an impairment of oil and gas properties of $0.9 million related to undeveloped leases representing 1,034 net acres in the D-J Basin that it allowed to expire or currently have no plans to drill prior to expiration, in the current period.

There was no impairment in the prior period.

General and Administrative Expenses (excluding share-based compensation).

The increase of $0.6 million in general and administrative expenses (excluding share-based compensation) was primarily due to increased contract and full time staff related to increased activity, an increase in accrued bonuses, which were subsequently paid in January 2025, software licensing fees and general increases in accounting and professional services when comparing the prior period to the current period.

Expenses increased by $9.5 million for the year ended December 31, 2025, compared to the prior period, primarily due to approximately $7.5 million of merger-related expenses.

The increase also reflects two additional months of payroll expense of approximately $0.5 million and $0.8 million in bonus accruals associated with the addition of 12 employees in connection with the Mergers, and higher legal and audit fees period over period.

Share-Based Compensation.

Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, decreased nominally due to the forfeiture of certain employee stock-based options due to certain voluntary employee terminations.

Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations.

Loss on Sale of Oil and Gas Properties, net .

The Company completed three oil and gas property sales transactions during the year ended December 31, 2024, for a total net loss on the sale of oil and gas properties of $76,000, as follows:

(i) the Company sold 30 gross (5.1 net) non-operated legacy well-bores in its D-J Basin Asset for net cash proceeds of $90,000 during 2024, resulting in the Company recognizing a loss on sale of oil and gas properties of $865,000 for these non-core assets, while noting.

the Company still retained the corresponding acreage related to the sale for any potential future development;

(ii) the Company sold a legacy well-bore assignment for net cash proceeds of $25,000 and recognized a gain on sale of oil and gas properties of $29,000;

and (iii) the Company sold leasehold rights to 320 net acres located in the D-J Basin for net cash proceeds of $750,000 and recognized a corresponding gain on sale of oil and gas properties of $735,000, as the leasehold costs had been fully depleted.

In the prior period, the Company sold its then-wholly-owned subsidiary EOR Operating Company and related assets in the November 2023 Milnesand Sale and recognized the corresponding loss of $4.3 million.

(see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”).

Interest Income and Other (Expense) Income.

Includes interest earned from our interest-bearing cash accounts, for which interest rates have remained relatively flat in the current period, compared to the prior period, and interest on our note receivable.

Other expense in the current period primarily relates to the subsequent disposition of a cash escrow bank balance related to the Milnesand Sale.

Other income in the prior period is primarily related to the sale of used pipe.

Share-based compensation expense, which is included in general and administrative expenses in the Consolidated Statements of Operations, increased by $0.9 million for the year ended December 31, 2025, compared to the prior period.

The increase was primarily attributable to the accelerated vesting of outstanding restricted common stock held by certain Board members who resigned, as well as the grant of restricted common stock to newly appointed Board members in connection with the Mergers.

Gain (Loss) on Sale of Oil and Gas Properties, net.

Represents a g ain on sale of oil and gas properties of $1.0 million related to the Company’s sale of all of its legacy 17 gross (15.4 net) operated wells in its D-J Basin Asset during the year ended December 31, 2025.

Also, the Company entered into a participation agreement under which a third party acquired 5%–22% working interests in 10 wellbores for which the purchaser carried the Company’s share of related capital expenditures for the drilling and completion of certain wells.

As a result, the Company recognized an additional $1.6 million gain on the sale of oil and gas properties for a combined total of $2.6 million During the year ended December 31, 2024, the Company completed three oil and gas property sales transactions, resulting in a net loss on sale of oil and gas properties of $76,000.

The transactions included (i) the sale of 30 gross (5.1 net) non-operated legacy well-bores in the D-J Basin for $90,000, resulting in a loss of $865,000 (with the Company retaining the related acreage), (ii) the sale of a legacy well-bore assignment for $25,000, resulting in a gain of $54,000, and (iii) the sale of 320 net acres of leasehold rights in the D-J Basin for $750,000, resulting in a gain of $735,000, as the associated leasehold costs were fully depleted.

Gain on Sale of Fixed Asset.

Relates to the sale of a vehicle and the subsequent purchase of another vehicle in the current period.

Relates to the sale of a vehicle and the subsequent purchase of another vehicle in the prior period.

We had no sales of fixed assets during the current period.

Note receivable – credit loss.

Represents the full write-off our Tilloo Note receivable and accrued interest as well as a post-closing adjustments receivable related to the sale of our then wholly-owned subsidiary EOR Operating Company in November 2023.

Net gain on derivative contracts.

In connection with the Mergers, certain derivative contracts were novated to the Company on November 1, 2025.

As of December 31, 2025, the Company recognized a total gain of $6.3 million related to these derivative contracts.

Of this amount, the Company recorded a realized gain of $2.1 million from derivative contract settlements, primarily due to crude oil prices at the time of settlement being above the fixed prices specified in the contracts.

The Company also recorded an unrealized gain of $4.1 million related to the mark-to-market valuation of outstanding derivative contracts.

The unrealized gain primarily reflects the novation of favorable derivative contracts during late 2025.

(see “ Item 8.

Financial Statements and Supplementary Data ” - Note 6 – Merger Acquisition and “ Note 10 – Derivatives ”).There were no derivative contracts in the prior period.

Interest expense .

Interest expense increased by $1.4 million for the year ended December 31, 2025, compared to the prior period.

Interest expense for the current period consisted of $1.1 million of interest incurred under the Company’s credit facility and $0.3 million related to the amortization of deferred financing costs.

No interest expense or amortization of deferred financing costs was recorded in the prior period.

Interest Income and Other Income (Expense).

Interest income, which includes interest earned on the Company’s interest-bearing cash accounts and interest on a note receivable, decreased compared to the prior period.

The decrease was primarily attributable to lower average cash balances used to fund operations and the absence of interest income from the note receivable, which was fully written off in the current period.

Other income in the current period primarily relates to sales tax refunds.

Other expense in the prior period was primarily associated with the subsequent disposition of a cash escrow balance related to the sale of the Company’s former wholly owned subsidiary, EOR Operating Company.

Liquidity and Capital Resources

The primary sources of cash for the Company during the year ended December 31, 2024 were from $39.6 million in sales of crude oil and natural gas.

The primary uses of cash were funds used for drilling, completion, acquisition and operating costs.

The primary sources of cash for the Company during the year ended December 31, 2025 were from a draw down from our A&R Credit Agreement of $87.0 million, a private placement of Series A Convertible Preferred Stock of $35.0 million and $45.0 million in sales of crude oil and natural gas.

The primary uses of cash were funds used for our Mergers and drilling, completion, acquisition and operating costs.

Working Capital

At December 31, 2024, the Company’s total current assets of $13.2 million exceeded its total current liabilities of $6.9 million, resulting in a working capital surplus of $6.3 million, while at December 31, 2023, the Company’s total current assets of $24.6 million exceeded its total current liabilities of $18.9 million, resulting in a working capital surplus of $5.7 million.

Although current assets and current liabilities both decreased when comparing periods, the $0.6 million net increase in our working capital surplus is primarily related to a larger reduction in accounts payable and accrued expenditures compared to the corresponding smaller reduction in current assets when comparing the current period to the prior period due to the timing of cash payments related to our drilling, as operator, and our participation in the drilling and completion of wells by a third-party operator.

(see “ Item 8.

At December 31, 2025, the Company’s total current liabilities of $64.5 million exceeded its total current assets of $37.8 million, resulting in a working capital deficit of $26.7 million.

At December 31, 2024, the Company’s total current assets of $13.2 million exceeded its total current liabilities of $6.9 million, resulting in a working capital surplus of $6.3 million.

The net decrease in our working capital is primarily related to our Mergers whereby the Company assumed an additional $23.5 million in net current liabilities (see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 6 - Merger Acquisition ”).

Additional decreases are primarily related to an increase in payables and expenses related to our current capital drilling program, when comparing the current period to the prior period (see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”).

The Company has an ongoing $8.0 million offering of securities in an “at the market offering”, pursuant to which the Company may sell securities from time to time (the “ ATM Offering ”).

The ATM Offering was made pursuant to the terms of a December 20, 2024, Sales Agreement (the “ Sales Agreement ”) with Roth Capital Partners, LLC and A.G.P./Alliance Global Partners.

During the month of June 2025, the Company sold an aggregate of 24,498 shares of common stock in five separate sales at a sales prices ranging between $14.32 to $16.02 per share via an ongoing “at the market offering” (for net proceeds of $354,000, which includes $11,000 in commission fees).

The Company also incurred $214,000 in initial and subsequent legal and audit-related fees and expenses incurred in connection with the registration and placement of the ATM Offering.

As of December 31, 2025, a total of $7.6 million is available for future sales of common stock under the ATM Offering.

The ATM Offering was made pursuant to the terms of that certain December 20, 2024, Sales Agreement (the “ Sales Agreement ”), entered into with Roth Capital Partners, LLC (the “ Lead Agent ”) and A.G.P./Alliance Global Partners (“ AGP ”, and collectively with the Lead Agent, the “ Agents ”), pursuant to which the Company may sell securities from time to time in an “at the market offering”.

The Company will pay the Lead Agent a commission of 3.0% of the gross sales price of any shares sold under the Sales Agreement.

The Company also agreed to reimburse the Agents for their reasonable and documented out-of-pocket expenses in an amount not to exceed $75,000, in connection with entering into the Sales Agreement and for the Agents’ reasonable and documented out-of-pocket expenses related to quarterly maintenance of the Sales Agreement on a quarterly basis in an amount not to exceed $5,000.

The Company has not sold any securities under the ATM Offering as of the date of this report.

Our net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million, including $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2.5 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and Area of Mutual Interest (AMI) entered into in August 2024 with a private operator.

This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated.

Our net capital expenditures for 2026 are estimated at the time of this filing to range between $16 million to $20 million.

This estimate includes a range of $6 million to $7 million for drilling and completion costs on our D-J Basin Assets (of which approximately $3 million is carry over from our 2025 program) and approximately $10 million to $13 million in estimated capital expenditures for optimization projects on the newly acquired assets from the Mergers.

These optimization projects include jet pump to rod pump or gas lift conversions, electronic submersible pump (ESP) to rod pump conversions, compression optimization projects, recompletions, and well cleanouts that are expected to materially lower lease operating expenses on our operated assets going forward.

Other minor capital expenditures included in these figures are leasing, facilities, remediation and other miscellaneous capital expenses.

We anticipate that approximately 90% of our expected capital expenditures for 2026 will be allocated to the D-J Basin and 10% will be allocated to the Powder River and Permian Basins.

These estimates do not include any expenditures for acquisitions or other projects that may arise but are not currently anticipated.

We are evaluating future development plans for late 2026 and 2027 as we integrate the assets and operations acquired in the Merger and execute the near-term optimization program outlined above.

We periodically review our capital expenditures and adjust our capital forecasts and allocations based on liquidity, drilling results, leasehold acquisition opportunities, partner non-consents, proposals from third party operators, and commodity prices, while prioritizing our financial strength and liquidity (see “ Part I ” – “ Item 1A.

Risk Factors ”).

We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective.

If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and nearly 100% held by production (“ HBP ”), allowing for flexibility of timing on development.

We plan to continue to evaluate D-J Basin non-operated well proposals as received from third party operators and participate in those we deem most economic and prospective.

If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to expand our capital program or move capital from our operated D-J Basin, Powder River Basin, and Permian Basin assets, allowing for flexibility on timing of development.

Our 2026 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) borrowing under our reserve-based lending facility (“ RBL ”) with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $20 million and an aggregate maximum revolving credit amount of $250 million (of which none has been drawn down by the Company to date), (iv) equity infusions or loans (which may be convertible) made available from Dr.

Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, which funding Dr.

Kukes is under no obligation to provide, (v) public or private debt or equity financings, including up to $8.0 million in securities which we may sell in the future in “at the market offerings”, pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the “ Lead Agent ”), and A.G.P./Alliance Global Partners (“ AGP ” and, together with the Lead Agent, the “ Agents ”)(discussed in greater detail below under “ Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing ” (under which we have sold no shares to date), and (vi) funding through other credit or loan facilities.

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund the remaining portion of our 2026 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) borrowing under our A&R Credit Agreement with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $120 million and an aggregate maximum revolving credit amount of $250 million (of which $98 million has been drawn down by the Company to date to fund the Mergers, participation in non-operated wells operations, and other Company payables), as discussed below, (iv) public or private debt or equity financings, pursuant to the ATM Offering noted above, and (v) funding through other credit or loan facilities.

In addition, we may seek additional funding through asset sales, farm-out arrangements, and partnerships to fund potential acquisitions during the remainder of 2026.

On October 31, 2025, the Company entered into the Amended and Restated Credit Agreement, which amended and restated that prior senior secured revolving credit agreement entered into on September 11, 2024 (the “ Original Credit Agreement ”) among the Company, as borrower, Citibank, N.A., as administrative agent (the “ Administrative Agent ”), and the lenders from time to time party thereto (the “ Lenders ”).

The A&R Credit Agreement has a maturity date of October 31, 2029.

The A&R Credit Agreement provides for an initial borrowing base and aggregate elected commitments of $120 million and an aggregate maximum revolving credit amount of $250 million.

The Company has drawn down $98 million under the Facility as of the filing date of this Report.

The A&R Credit Agreement includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Company from creating any indebtedness without the consent of the Lenders, subject to certain exceptions, and the maintenance of the following financial ratios:

(i) a current ratio, which is the ratio of the Company’s consolidated current assets (including unused commitments under the A&R Credit Agreement and excluding non- cash derivative assets) to its consolidated current liabilities (excluding the current portion of long-term debt under the A&R Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and (ii) a leverage ratio, which is the ratio of Total Net Debt to EBITDAX (each as defined in the A&R Credit Agreement) for the prior four fiscal quarters, of not greater than 3.0 to 1.0.

The Company is required to hedge at least 75% of its projected proved developed producing reserves (PDP) oil and gas production at the time of entry into the A&R Credit Agreement, for the first 24 months of the agreement, and 50% of its projected PDP of oil and gas production for months 25-36.

Afterward, within 60 days after each fiscal quarter, the Company must show it has hedged at least 50% of expected oil and gas production for the next 18 months.

The Company may hedge crude oil, natural gas, or natural gas liquids (on a barrel of oil equivalent basis) to meet these requirements, but may not hedge more than 75% of anticipated production (on a barrel of oil equivalent basis) for any month.

Cash Flows (in thousands)

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Cash provided by operating activities.

Net cash provided by operating activities decreased by $10.7 million for the current year’s period, when compared to the prior year’s period, primarily due to our net income for the current period increasing by $5.6 million and from a $4.2 million increase in depreciation, depletion, amortization and accretion (primarily due to increased sales production, noted above), offset by a $4.2 million net loss on sale of oil and gas properties (primarily from a $4.3 million loss on the sale of our EOR Operating Company subsidiary and its corresponding assets in the prior period) and by a $16.3 million net decrease to our other components of working capital in the current period (due to increased cash payments and decreased payables and expenses outstanding from our drilling and completion activity) when comparing periods.

Net cash provided by operating activities decreased by $2.0 million in the current year compared to the prior year, primarily due to the Company’s Mergers, whereby we assumed approximately $23.5 million in net current liabilities (see “ Item 8.

Financial Statements and Supplementary Data ” - Note 6 – Merger Acquisition ”).

This increase was partially offset by a decrease in net income and an increase in overall operating expenses (including, but not limited to, $7.5 million of merger-related acquisition costs and $1.3 million of additional payroll costs), as well as a $15.3 million increase in deferred income tax.

Operating cash flow was also impacted by a $2.1 million increase in depreciation, depletion and amortization, a $0.9 million impairment of oil and gas properties, $4.2 million in initial derivative activity, a $1.4 million credit loss on a note receivable, and additional changes in other components of working capital.

Cash used in investing activities.

Net cash used in investing activities decreased by $8.9 million for the current year’s period, when compared to the prior year’s period, primarily due to decreased cash outlays from our capital spending relating to our drilling and completion activities.

Net cash used in investing activities increased by $106.3 million for the current year’s period, when compared to the prior year’s period, primarily due to our Mergers (see “ Item 8.

Financial Statements and Supplementary Data ” - Note 6 – Merger Acquisition ”).

Cash financing activities.

There were no cash flow financing activities in the current or prior period.

Consisted of a $87.0 million drawdown on our credit facility and the issuance of convertible preferred stock of $35.0 million related to our Mergers (see “ Item 8.

Financial Statements and Supplementary Data ” - Note 6 – Merger Acquisition ”), and sales of our common stock via our ATM Offering in the current period (discussed above).

There were no cash flow financing activities in the prior period.

Non-GAAP Financial Measures

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“EBITDA” represents net income before interest, taxes, depreciation and amortization.

“Adjusted EBITDA” represents EBITDA, less share-based compensation, loss on sale of oil and gas properties, net, and gain on sale of fixed assets.

“Adjusted EBITDA” represents EBITDA, less share-based compensation, impairment of oil and gas properties, gain on sale of oil and gas properties, gain on sale of fixed asset, merger acquisition costs and note receivable – credit loss.

Adjusted EBITDA excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated.

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The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDA (in thousands):

(As Restated)

Income tax benefit

Years Ended December 31,

Net (loss) income

Interest expense

Income tax expense (benefit)

Depreciation, depletion, amortization and accretion

Share-based compensation

Loss on sale of oil and gas properties, net

Gain on sale of fixed assets

Merger acquisition costs

Impairment of oil and gas properties

(Gain) loss on sale of oil and gas properties

Gain on sale of fixed asset

Note receivable – credit loss

Adjusted EBITDA

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We have opted to use the simplified method for estimating expected term, which is equal to the midpoint between the vesting period and the contractual term.

Business Combinations.

The Company accounts for business combinations using the acquisition method, recording oil and gas assets acquired and liabilities assumed at estimated fair values.

Fair values are determined using discounted cash flows, market comparables, and other valuation techniques, with significant judgment applied to estimates of reserves, future commodity prices, and operating and development costs.

Purchase price allocations may be adjusted during a one-year measurement period.

The Merger Acquisition was completed on October 31, 2025 and has been accounted for under the acquisition method of accounting in accordance with ASC 805, Business Combinations (" ASC 805"), PEDEVCO was treated as the acquirer for accounting purposes.

Under the acquisition method of accounting, the assets and liabilities of Acquired Companies have been recorded at their respective fair values as of the acquisition date on October 31, 2025.

As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after October 31, 2025.

See Note 6 – Merger Acquisition for additional information.

Recently Adopted Accounting Pronouncements .

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280).

The amendments in this update expand segment disclosure requirements, including new segment disclosure requirements for entities with a single reportable segment among other disclosure requirements.

This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.

Adoption of this standard is on a modified retrospective basis and had no impact on the Company’s financial position, results of operations, cash flows or net income per share.

Recently Issued Accounting Pronouncements .

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740):

Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures.

This ASU will be effective for the annual period ending December 31, 2025.

The Company is currently evaluating the timing and impacts of adoption of this ASU.

The Company adopted this ASU on December 31, 2025 and has reflected the required disclosures in the accompanying notes to the consolidated financial statements.

The ASU had no impact on the Company’s consolidated balance sheets, consolidated statements of operations or consolidated statements of cash flows.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.

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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 7. Management’s Discussion and Analysis