Item 7. Management’s Discussion and Analysis
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 should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “ forward-looking statements ” that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “ Risk Factors ” and “ Forward-Looking Statements . ”
Summary of The Information Contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is provided in addition to the accompanying consolidated financial statements and notes to assist readers in understanding our results of operations, financial condition, and cash flows. Our MD&A is organized as follows:
·
Overview . Discussion of our business and overall analysis of financial and other highlights affecting us, to provide context for the remainder of our MD&A.
·
Results of Operations . An analysis of our financial results comparing the years ended December 31, 2025 and 2024.
·
Liquidity and Capital Resources . An analysis of changes in our consolidated balance sheets and cash flows and discussion of our financial condition.
·
Critical Accounting Estimates . Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts.
Overview
We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. 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 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. ( PEDCO ”. 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.”
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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.
How We Conduct Our Business and Evaluate Our Operations
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe have significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
·
production volumes;
·
realized prices on the sale of oil and natural gas;
·
oil and natural gas production and operating expenses;
·
capital expenditures;
·
general and administrative expenses;
·
net cash provided by operating activities; and
·
net income.
Reserves
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 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, 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. A large portion of the proved undeveloped crude oil reserves are associated with our D-J Basin Asset. Although these hydrocarbon quantities have been determined in accordance with industry standards, they are prepared using the subjective judgments of the independent engineers and may actually be more or less.
Oil and Natural Gas Sales Volumes
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 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).
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Significant Capital Expenditures
The table below sets out the significant components of capital expenditures for the year ended December 31, 2025 (in thousands):
Capital Expenditures
Leasehold Acquisitions
$ 400
Mineral Acquisitions
200
Merger Acquisition
204,600
Drilling and Facilities
34,000
Total*
$ 239,200
*see “ Item 8. Financial Statements and Supplementary Data ” - “ Note 6 – Merger Acquisition and Note 7 - Oil and Gas Properties ”.
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. We expect prices to remain volatile for the remainder of the year. For information about the impact of realized commodity prices on our crude oil and natural gas and condensate revenues, refer to “ Results of Operations ” below.
Results of Operations
The following discussion and analysis of the results of operations for each of the two fiscal years in the years ended December 31, 2025 and 2024 should be read in conjunction with the consolidated financial statements of PEDEVCO Corp. and notes thereto included herein (see “ Item 8. Financial Statements and Supplementary Data ”). 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 $8.1 million (see in the notes to the consolidated financial statements under “ Item 8. Financial Statements and Supplementary Data ” - “ Note 17 – Income Taxes ”).
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Net Revenues
The following table sets forth the revenue and production data for the years ended December 31, 2025 and 2024:
2025
2024
Increase
(Decrease)
%
Increase
(Decrease)
Sale Volumes:
Crude Oil (Bbls)
672,924
492,396
180,528
37 %
Natural Gas (Mcf)
770,919
608,382
162,537
27 %
NGL (Bbls)
108,657
78,003
30,654
39 %
Total (Boe) (1)
910,068
671,796
238,272
35 %
Crude Oil (Bbls per day)
1,844
1,345
499
37 %
Natural Gas (Mcf per day)
2,112
1,662
450
27 %
NGL (Bbls per day)
298
213
85
40 %
Total (Boe per day) (1)
2,494
1,835
659
36 %
Average Sale Price:
Crude Oil ($/Bbl)
$ 59.78
$ 73.50
$ (13.72 )
(19
%)
Natural Gas($/Mcf)
3.45
2.00
1.45
73 %
NGL ($/Bbl)
26.30
27.48
(1.18 )
(4
%)
Net Operating Revenues (In thousands):
Crude Oil
$ 40,230
$ 36,193
$ 4,037
11 %
Natural Gas
2,663
1,216
1,447
119 %
NGL
2,858
2,144
714
33 %
Total Revenues
$ 45,751
$ 39,553
$ 6,198
16 %
(1)
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, 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
% Increase
2025
2024
(Decrease)
(Decrease)
Direct Lease Operating Expenses
$ 10,578
$ 6,961
$ 3,617
52 %
Workovers
1,289
839
450
54 %
Other*
7,253
4,649
2,604
56 %
Total Lease Operating Expenses
$ 19,120
$ 12,449
$ 6,671
54 %
Depreciation, Depletion,
Amortization and Accretion
$ 18,009
$ 15,920
$ 2,089
13 %
Impairment of Oil and Gas Properties
$ 908
$ -
$ 908
100 %
General and Administrative (Cash)
$ 14,025
$ 4,532
$ 9,493
209 %
Share-Based Compensation (Non-Cash)
2,763
1,859
904
49 %
Total General and Administrative Expense
$ 16,788
$ 6,391
$ 10,397
163 %
Gain (Loss) on Sale of Oil and Gas Properties, net
$ 2,597
$ (76 )
$ 2,673
3,517 %
Gain on Sale of Fixed Asset
$ -
$ 12
$ (12 )
(100
%)
Note Receivable – Credit Loss
$ 1,378
$ -
$ 1,378
100 %
Net gain on derivative contracts
$ 6,253
$ -
$ 6,253
100 %
Interest Expense
$ 1,407
$ -
$ 1,407
100 %
Interest Income
$ 274
$ 351
$ (77 )
(22
%)
Other Income (Expense)
$ 428
$ (42 )
$ 470
1,119 %
* Includes severance, ad valorem taxes, assessment and gathering, transportation and processing costs.
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Lease Operating Expenses. 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. 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). 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 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 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.
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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, 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, 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 ”).
Financing
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 ”). 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.
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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 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 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.
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Cash Flows (in thousands)
Year Ended December 31,
2025
2024
Cash flows provided by operating activities
$ 10,758
$ 12,766
Cash flows used in investing activities
(133,183 )
(26,874 )
Cash flows provided by financing activities
122,139
-
Net decrease in cash and restricted cash
$ (286 )
$ (14,108 )
Cash provided by operating activities. 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 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. 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
We have included EBITDA and Adjusted EBITDA in this Report as supplements to generally accepted accounting principles in the United States of America (“ GAAP ”) measures of performance to provide investors with an additional financial analytical framework which management uses, in addition to historical operating results, as the basis for financial, operational and planning decisions and present measurements that third parties have indicated are useful in assessing the Company and its results of operations. “EBITDA” represents net income before interest, taxes, depreciation and amortization. “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. EBITDA and Adjusted EBITDA are presented because we believe they provide additional useful information to investors due to the various noncash items during the period. EBITDA and Adjusted EBITDA are also frequently used by analysts, investors and other interested parties to evaluate companies in our industry. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA and Adjusted EBITDA do not reflect cash expenditures, future requirements for capital expenditures, or contractual commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and EBITDA and Adjusted EBITDA do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments. For example, although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Additionally, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than PEDEVCO Corp. does, limiting its usefulness as a comparative measure. You should not consider EBITDA and Adjusted EBITDA in isolation, or as substitutes for analysis of the Company’s results as reported under GAAP. The Company’s presentation of these measures should not be construed as an inference that future results will be unaffected by unusual or nonrecurring items. We compensate for these limitations by providing a reconciliation of each of these non-GAAP measures to the most comparable GAAP measure. We encourage investors and others to review our business, results of operations, and financial information in their entirety, not to rely on any single financial measure, and to view these non-GAAP measures in conjunction with the most directly comparable GAAP financial measure. 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):
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Years Ended December 31,
2025
2024
Net (loss) income
$ (10,362 )
$ 12,293
Add (deduct)
Interest expense
1,407
-
Income tax expense (benefit)
8,055
(7,255 )
Depreciation, depletion, amortization and accretion
18,009
15,920
EBITDA
17,109
20,958
Add (deduct)
Share-based compensation
2,763
1,859
Merger acquisition costs
7,457
-
Impairment of oil and gas properties
908
-
(Gain) loss on sale of oil and gas properties
(2,597 )
76
Gain on sale of fixed asset
-
(12 )
Note receivable – credit loss
1,378
-
Adjusted EBITDA
$ 27,018
$ 22,881
Critical Accounting Estimates
Our discussion and analysis of our financial condition and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our most significant judgments and estimates used in preparation of our financial statements.
Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise, the related well costs are expensed as dry holes.
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Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above.
Depreciation, depletion and amortization of capitalized oil and gas properties is calculated on a field-by-field basis using the unit of production method. Lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves and all other capitalized costs are amortized over proved developed reserves. Costs specific to developmental wells for which drilling is in progress or uncompleted are capitalized as wells in progress and not subject to amortization until completion and production commences, at which time amortization on the basis of production will begin.
Asset Retirement Obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the unit-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in DD&A expense in the Consolidated Statement of Operations.
Revenue Recognition. The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.
Contracts with customers have varying terms, including month-to-month contracts, and contracts with a finite term. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.
Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.
Stock-Based Compensation. Pursuant to the provisions of Financial Accounting Standards Board (“ FASB ”) Accounting Standards Codification (“ ASC ”) 718, Compensation – Stock Compensation, which establishes accounting for equity instruments exchanged for employee service, we utilize the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. We estimate volatility by considering historical stock volatility. 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 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. 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
Not required under Regulation S-K for “ smaller reporting companies .”
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