PED 10-K & 10-Q changes, risk factors and insider trading
Pedevco Corp. · NYSE · Crude Petroleum & Natural Gas · CIK 1141197 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Our business operations may be affected by worldwide economic, political and miliary events, including certain ongoing conflicts.”
New heading “Volatility in oil and gas prices makes it hard for us to plan and project our operations, capital expenditures, and financial performance.”
New heading “Approximately 49% of our total proved reserves are classified as proved undeveloped and may ultimately prove to be less than estimated.”
New heading “If actual reserves are lower than anticipated, the financial condition and results of operations of the Company could be adversely affected.”
New heading “Approximately 181,093 net acres in the PRB are located on federal lands as of December 31, 2025, which are subject to administrative permitting requirements, current and potential federal legislation, regulation and orders and pending litigation that may limit or restrict oil and natural gas operations on federal lands.”
New heading “Our hedging activities may prevent us from fully benefiting from increases in crude oil, natural gas and NGLs prices and may expose us to other risks, including counterparty risk, and our future production may not be sufficiently protected from any declines in commodity prices by our existing or future hedging arrangements.”
New heading “New or revised rules, regulations and policies may be issued, and new legislation may be proposed, that could impact the oil and gas exploration and production industry.”
New heading “We have previously concluded that certain of our previously issued financial statements should not be relied upon and have restated certain of our previously issued financial statements which may affect investor confidence and raise reputational issues and may subject us to additional risks and uncertainties, including increased professional costs and the increased possibility of legal proceedings and regulatory inquiries.”
New heading “Risks Relating to the Mergers”
New heading “Combining the businesses of NPOG and COG with the Company may be more difficult, costly or time-consuming than expected and the Company may fail to realize the anticipated synergies and other benefits of the Mergers, which may adversely affect the Company’s business results and negatively affect the value of our Common Stock.”
New heading “The Company may not be able to retain suppliers or distributors, or suppliers or distributors may seek to modify contractual relationships with the Company, which could have an adverse effect on the Company’s business and operations. Third parties may terminate or alter existing contracts or relationships with the Company.”
New heading “The Acquired Companies were not U.S. public reporting companies prior to the closing of the Mergers, and the obligations associated with integrating into a public company may require significant resources and management attention.”
New heading “The Company’s ability to utilize its net operating loss carryforwards and tax credit carryforwards may be subject to limitations.”
Removed heading “We have concluded that certain of our previously issued financial statements should not be relied upon and have restated certain of our previously issued financial statements which may affect investor confidence and raise reputational issues and may subject us to additional risks and uncertainties, including increased professional costs and the increased possibility of legal proceedings and regulatory inquiries.”
Removed heading “Our industry and the broader US economy have experienced higher than expected inflationary pressures in 2022, related to continued supply chain disruptions, labor shortages and geopolitical instability. Should these conditions persist our business, results of operations and cash flows could be materially and adversely affected.”
Removed heading “We may not be able to generate sufficient cash flow to meet any future debt service and other obligations due to events beyond our control.”
Removed heading “If we do not hedge our exposure to reductions in oil and natural gas prices, we may be subject to significant reductions in prices. Alternatively, we may use oil and natural gas price hedging contracts, which involve credit risk and may limit future revenues from price increases and result in significant fluctuations in our profitability.”
Removed heading “The $1.1 million owed to us under a secured convertible promissory note due from Tilloo in the Milnesand Sale may not be repaid.”
Removed heading “We have in the past been significantly dependent on capital provided to us by Dr. Simon G. Kukes and may rely on Dr. Kukes for additional funding in the future.”
Removed heading “Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Colorado forced pooling system and drilling operation set-back rules, salt water disposal permitting regulations in New Mexico or Wyoming, and new federal orders restricting operations on federal lands, could have a material adverse effect on our business.”
Largest changes
“As a result of the errors discussed above and the resulting restatements of our consolidated financial statements for the impacted periods, we have incurred, and may continue to incur, unanticipated costs for accounting, legal and other professional fees in connection with or related to the restatement, and have become subject to a number of additional risks and uncertainties. These include, among other things, an increased risk of shareholder litigation, including securities class actions and derivative lawsuits, as well as regulatory inquiries and investigations. …”see in full comparison
“Year 2022 saw significant increases in the costs of certain services and materials, including steel, sand and fuel, as a result of availability constraints, supply chain disruption, increased demand, labor shortages associated with a fully employed US labor force, high inflation, interest rates and other factors, with supply and demand fundamentals being further aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing conflict between Russia and Ukraine and the current armed conflict in Israel and the Gaza Strip, all resulting in an …”see in full comparison
“Worldwide economic, political and military events, including tax, trade and tariff policies of the United States and other countries involved in global energy markets, war, terrorist activity, events in the Middle East and initiatives by OPEC+, have contributed, and are likely to continue to contribute, to oil and natural gas price volatility. …”see in full comparison
“Our industry and the broader US economy have experienced higher than expected inflationary pressures in 2022, related to continued supply chain disruptions, labor shortages and geopolitical instability. Should these conditions persist our business, results of operations and cash flows could be materially and adversely affected.”see in full comparison
“Approximately 181,093 net acres in the PRB are located on federal lands as of December 31, 2025, which are subject to administrative permitting requirements, current and potential federal legislation, regulation and orders and pending litigation that may limit or restrict oil and natural gas operations on federal lands.”see in full comparison
“In 2018 and 2019, Dr. Simon G. Kukes, the Company’s former Chief Executive Officer and director and current Executive Chairman of the Company's Board of Directors, loaned us an aggregate of $51.7 million to support our operations and for acquisitions through an entity owned and controlled by him, all of which loans were evidenced by promissory notes. …”see in full comparison
Full comparison: every changed paragraph (108)
The price we receive for our oil and, to a lesser extent, natural gas and NGLs, heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, the nature and scale of our operations and future rate of growth. Oil, NGL and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 60%72% of our estimated proved reserves as of December 31, 20242025 were oil, our financial results are more sensitive to movements in oil prices. The price of crude oil has experienced significant volatility over the last five years, with the price per barrel of West Texas Intermediate (“WTI”) crude, dropping below $20$48 per barrel in 2020 due in part to reduced global demand stemming from the global COVID-19 outbreak,2021 and surging to over $120 a barrel in early March 2022, following Russia’s invasion of the Ukraine, to the $70s$90s in early 2026, and more recently increasing again to the mid-$90s per barrel following the initiation of the recent months.conflict in Iran . A prolonged period of low market prices for oil and natural gas, or further declines in the market prices for oil and natural gas, will likely result in capital expenditures being further curtailed and will adversely affect our business, financial condition and liquidity and our ability to meet obligations, targets or financial commitments and could ultimately lead to restructuring or filing for bankruptcy, which would have a material adverse effect on our stock price and indebtedness. Additionally, lower oil and natural gas prices have, and may in the future, cause, a decline in our stock price. The below table highlights the recent volatility in oil and gas prices by summarizing the high and low daily NYMEX WTI oil spot price and daily NYMEX natural gas Henry Hub spot price for the periods presented:
* Through March 16, 2026.
We may need additional capital to complete future acquisitions,acquisitions and conduct our operations and fund our business in and beyond 2025,2026, and will need to raise additional capital to repay outstanding liabilities, and our ability to obtain the necessary funding is uncertain.
We may need additional capital to complete future acquisitions and conduct our operations and fund our business in and beyond 2026, and will need to raise additional fundingcapital to completerepay futureoutstanding potential acquisitionsliabilities, and may be required to raise additional funds through public or private debt or equity financing or other various means to repay outstanding liabilities, fund our operations and complete exploration and drilling operations in and beyond 20252026 and acquire assets. In such a case, adequate funds may not be available when needed or may not be available on favorable terms. If we need to raise additional funds in the future by issuing equity securities, including sales of common stock under our December 2024 Sales Agreement entered into with Roth Capital Partners, LLC and A.G.P./Alliance Global Partners, pursuant to which we can sell up to $8 million in at-the-market offerings, dilution to existing stockholders will result, and such securities may have rights, preferences and privileges senior to those of our common stock.stock, and/or through drawing debt under our A&R Credit Agreement. If funding is insufficient at any time in the future and we are unable to generate sufficient revenue from new business arrangements, to complete planned acquisitions or operations, our results of operations and the value of our securities could be adversely affected.
As of the date of this Report, we owe $98.0 million under our A&R Credit Agreement, which amounts are due and payable on October 31, 2029. Such funds may not be available when needed or may not be available on favorable terms.
We have concluded that certain of our previously issued financial statements should not be relied upon and have restated certain of our previously issued financial statements which may affect investor confidence and raise reputational issues and may subject us to additional risks and uncertainties, including increased professional costs and the increased possibility of legal proceedings and regulatory inquiries.
As discussed in Note 4 to our audited consolidated financial statements included under Restatement of Previously Issued Consolidated Financial Statements, we determined to restate our consolidated financial statements as of December 31, 2023 and 2022, respectively, after we identified errors in our calculation of depletion expenses for our oil and gas properties. As a result of this error and the resulting restatement of our consolidated financial statements for the impacted periods, we have incurred, and may continue to incur, unanticipated costs for accounting and legal fees in connection with or related to the restatement, and have become subject to a number of additional risks and uncertainties, including the increased possibility of litigation and regulatory inquiries. Any of the foregoing may affect investor confidence in the accuracy of our financial disclosures and may raise reputational risks for our business, both of which could harm our business and financial results.
Our industry and the broader US economy have experienced higher than expected inflationary pressures in 2022, related to continued supply chain disruptions, labor shortages and geopolitical instability. Should these conditions persist our business, results of operations and cash flows could be materially and adversely affected.
Year 2022 saw significant increases in the costs of certain services and materials, including steel, sand and fuel, as a result of availability constraints, supply chain disruption, increased demand, labor shortages associated with a fully employed US labor force, high inflation, interest rates and other factors, with supply and demand fundamentals being further aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing conflict between Russia and Ukraine and the current armed conflict in Israel and the Gaza Strip, all resulting in an estimated cost increase of approximately 25% to 30% per well on our Permian Asset and 10% to 20% on our D-J Basin Asset, based on costs we experienced commencing in the third quarter of 2021 and continuing throughout 2022. Service and materials costs also increased accordingly through 2022, stabilizing in 2023 in 2024, with general supply chain and inflation issues seen throughout the industry leading to increased operating costs. While the Company is cautiously optimistic that such costs have plateaued and will hold at current levels as we have not seen significant cost increases in 2024 and thus far in 2025, supply chain constraints, the effect of tariffs, and inflationary pressures may adversely impact our operating costs and may negatively impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Recent increases in inflation have had an adverse effect on us. Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies, and geopolitical instability, including the ongoing conflict between the Ukraine and Russia and the currentrecent armed conflict in Israel and the Gaza Strip, and the ongoing conflicts between the Ukraine and Russia and the United States and Iran, and the effect of tariffs. Increases in inflation, have in the past, and could in the future, impact our costs of labor, equipment and services and the margins we are able to realize on our wells, all of which could have an adverse impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the past, which in turn raises our cost of debt borrowing.
Global economic conditions continue to be volatile and uncertain due to, among other things, consumer confidence in future economic conditions, ongoing wars and conflicts, including the ongoing conflict between the United States and Iran, fears of recession and trade wars, the effect of tariffs, the price of energy, fluctuating interest rates, the availability and cost of consumer credit, the availability and timing of government stimulus programs, levels of unemployment, increased inflation, and tax rates. These conditions remain unpredictable and create uncertainties about our ability to raise capital in the future. In the event required capital becomes unavailable in the future, or more costly, it could have a material adverse effect on our business, results of operations, and financial condition.
The Company has entered into an SFO with the OCD through RAZO, the Company’s New Mexico operating subsidiary, which requires, among other things, that the Company reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset (of which seven have been plugged to date) at a rate of $2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $30,000 per month by RAZO. .RAZORAZO has been timely paying each reimbursement invoice received from the OCD in accordance with the SFO and is in full compliance with the SFO. Such required payments and reimbursements may be significant, and may reduce our cash flows and funds available for our business plan and/or require us to raise additional funding in the future. Additionally, in the event the Company is unable to fully comply with the terms of the SFO, then the Company could be subject to significant civil penalties and sanctions, which would likely have a material adverse effect on our business, financial condition and results of operations, could require us to raise additional funding which may not be available on commercially reasonable terms, if at all, and may negatively affect our drilling plans in the future, and may cause the value of our securities to decline in value.
We may not be able to generate sufficient cash flow to meet any future debt service and other obligations due to events beyond our control.
Our ability to generate cash flows from operations, to make payments on or refinance potential future indebtedness and to fund working capital needs and planned capital expenditures will depend on our future financial performance and our ability to generate cash in the future. Our future financial performance will be affected by a range of economic, financial, competitive, business and other factors that we cannot control, such as general economic, legislative, regulatory and financial conditions in our industry, the economy generally, the price of oil and other risks described below. A significant reduction in operating cash flows resulting from changes in economic, legislative or regulatory conditions, increased competition or other events beyond our control could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service future potential debt and other obligations. If we are unable to service future potential indebtedness or to fund our other liquidity needs, we may be forced to adopt an alternative strategy that may include actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing such indebtedness, seeking additional capital, or any combination of the foregoing. If we raise debt, it would increase our interest expense, leverage and our operating and financial costs. We cannot assure you that any of these alternative strategies could be affected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on future potential indebtedness or to fund our other liquidity needs. Reducing or delaying capital expenditures or selling assets could delay future cash flows. In addition, the terms of future debt agreements may restrict us from adopting any of these alternatives. We cannot assure you that our business will generate sufficient cash flows from operations or that future borrowings will be available in an amount sufficient to enable us to pay such future potential indebtedness or to fund our other liquidity needs.
If for any reason we are unable to meet our future potential debt service and repayment obligations, we may be in default under the terms of the agreements governing such indebtedness, which could allow our creditors at that time to declare such outstanding indebtedness to be due and payable. Under these circumstances, our lenders could compel us to apply all of our available cash to repay our borrowings. In addition, the lenders under our credit facilities or other secured indebtedness could seek to foreclose on any of our assets that are their collateral. If the amounts outstanding under such indebtedness were to be accelerated, or were the subject of foreclosure actions, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders.
All of our crude oil, natural gas and NGLs production is located in the Permian Basin, the Powder River Basin and the D-J Basin, making us vulnerable to risks associated with operating in only twothree geographic areas. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.
Our current operations are focused solely in the Permian Basin located in Chaves and Roosevelt Counties, New Mexico, and the D-J Basin of Weld and Morgan Counties, Colorado, with potential future operations extending into the Powder River Basin in Campbell and Laramie County,Counties, Wyoming, as a result of our October 2025 Mergers, with which means our current producing properties and new drilling opportunities are geographically concentrated in those twothree areas. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including:
For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Permian BasinBasin, Powder River Basin, and D-J Basin may negatively affect our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Permian BasinBasin, the Powder River Basin, and D-J Basin, the demand for, and cost of, drilling rigs, equipment, supplies, personnel and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations.
The prices we receive for our oil, NGLs and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, NGLs and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. For example, the price of crude oil has experienced significant volatility over the last five years, with the price per barrel of West Texas Intermediate (“WTI”) crude, dropping below $20$48 per barrel in 2020 due in part to reduced global demand stemming from the global COVID-19 outbreak,2021, and surging to over $120 a barrel in early March 2022, following Russia’s invasion of the Ukraine, to the $70s$60s in early 2026, to around $98 more recently following the initiation of the recent months.conflict in Iran. Prices for natural gas and NGLs experienced declines of similar magnitude. An extended period of continued lower oil prices, or additional price declines, will have further adverse effects on us. The prices we receive for our production, and the levels of our production, will continue to depend on numerous factors, including the following:
Declines in oil, NGL or natural gas prices have not, and will not, only reduce our revenue, but have and will reduce the amount of oil, NGL and natural gas that we can produce economically. Should natural gas, NGL or oil prices decline from current levels and remain there for an extended period of time, we may choose to shut-in our operated wells, (similar to our shut-in of our operated wells in the Permian Basin and the D-J Basin in 2020 in response to the COVID-19 pandemic), delay some or all of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, and, as a result, we may have to make substantial downward adjustments to our estimated proved reserves, each of which would have a material adverse effect on our business, financial condition and results of operations.
We review our long-lived tangible and intangible assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. For example, for the year ended December 31, 2020, due to falling oil and gas prices, we incurred a $19.3 million impairment of our oil and gas properties.properties Nowith impairmentrespect wasto incurredour forD-J Basin properties, and during the years ended December 31, 2024 and 2023. In2023, the pastAcquired weCompanies haverecorded beenimpairment requiredcharges of $3.9 million and $21.1 million, respectively, with respect to impairtheir ourproved assetsand and,unproved ifoil conditionsand innatural anygas of the businesses in which we compete were to deteriorateproperties in the future,PRB for 2024 and both the PRB and D-J Basin for 2023. Aside from certain lease expirations, no significant impairment was incurred for the year ended December 31, 2025. We could be at risk for proved and unproved property impairments if we couldexperience determineadverse thatmarket certainconditions for an extended period of time. The carrying values of our assetsproperties wereare impairedsensitive to declines in oil, natural gas and NGL prices as well as increases in various development and operating costs and expenses. If oil, natural gas and NGL prices remain depressed for extended periods of time or decline materially from current levels, we would thenmay be required to write-offrecord alladditional orwrite-downs aof portionthe carrying value of our costsproved foroil suchand assets.natural gas properties. Further, we periodically evaluate our unproved oil and natural gas properties to determine the recoverability of our costs. Prior write-offs have adversely affected our balance sheet assets and results of operations and any future significant write-offs would similarly adversely affect our balance sheet and results of operations.
Concerns over global economic conditions, the duration and effects of future pandemics, and the results thereof, energy costs, geopolitical issues (including, but not limited to the current Ukraine/Russia and Israel/Gaza Strip conflictsconflict, the Ukraine/Russia conflict and the current Iran conflict), inflation, increasing interest rates and the availability and cost of credit have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, and declining business and consumer confidence, have precipitated an economic slowdown, which could expand to a recession or global depression. If the economic climate in the United States or abroad deteriorates, demand for petroleum products could diminish, which could further impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition to a greater extent that it has already.
Our business operations may be affected by worldwide economic, political and miliary events, including certain ongoing conflicts.
Worldwide economic, political and military events, including tax, trade and tariff policies of the United States and other countries involved in global energy markets, war, terrorist activity, events in the Middle East and initiatives by OPEC+, have contributed, and are likely to continue to contribute, to oil and natural gas price volatility. For example, recent events in Venezuela, the ongoing armed conflicts between Russia and Ukraine, and escalating tensions involving the United States, Israel and Iran, including direct military engagements and retaliatory actions, have led to heightened regional instability and increased global economic uncertainty. In particular, recent hostilities involving Iran have resulted in attacks on commercial shipping and energy infrastructure, as well as an effective disruption and, at times, near-total suspension of maritime traffic through the Strait of Hormuz, a critical chokepoint through which approximately 20% of the world’s oil supply transits.
The disruption of shipping lanes in and around the Persian Gulf, including congestion, rerouting and the anchoring of vessels outside the Strait of Hormuz, has caused significant delays in the transportation of crude oil, liquefied natural gas and refined products, and has contributed to increased freight, insurance and security costs, as well as volatility in global energy prices. In addition, damage to or disruption of key regional ports and infrastructure, including Iranian port facilities, and the risk of further military strikes or blockades, have exacerbated supply chain challenges and increased uncertainty regarding the availability and cost of energy commodities. The potential for broader regional conflict involving Iran, including possible prolonged closure or continued disruption of the Strait of Hormuz, as well as escalating hostilities involving the Houthi movement in Yemen, Hezbollah in Lebanon and other regional actors, has increased significantly.
Any continuation or escalation of these conflicts, including sustained disruptions to critical global shipping routes or energy infrastructure, could materially and adversely affect global supply and demand for oil and natural gas, increase commodity price volatility, disrupt our operations or those of our customers, suppliers or partners, and have a material adverse effect on our business, financial condition and results of operations.
Volatility in oil and gas prices makes it hard for us to plan and project our operations, capital expenditures, and financial performance.
Volatility in oil and natural gas prices, including for the reasons discussed in the risk factors above, significantly impairs our ability to accurately plan and project our operations, capital expenditures, and financial performance. These commodity prices are inherently unpredictable due to factors such as global supply and demand imbalances, geopolitical events, economic conditions, and regulatory changes, making it extremely difficult to forecast future price movements with any certainty. As a result, prolonged periods of low or highly volatile prices can lead to the reduction, deferral, or cancelation of exploration, development, and production activities, including but us or our operators. This uncertainty may force us to adjust our own capital spending plans, delay projects, revise budgets, and recalibrate internal projections and forecasts, which may result in reduced operational efficiency, impairments to proved reserves or other assets, and challenges in meeting financial targets or liquidity needs. For instance, sharp declines in prices can render certain development projects uneconomic, leading to lower-than-anticipated production volumes and cash flows, while sudden spikes may create inflationary pressures on costs without corresponding revenue gains in the near term. Ultimately, such price volatility contributes to greater unpredictability in our business planning, potentially materially and adversely affecting our results of operations, financial condition, and ability to execute our long-term strategy.
In addition, future events, such as terrorist attacks, wars,wars and conflicts, threat of wars,wars and conflicts, or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, pandemic diseases, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.
Approximately 49% of our total proved reserves are classified as proved undeveloped and may ultimately prove to be less than estimated.
On December 31, 2025, approximately 49% of our total proved reserves of oil, natural gas and NGLs were classified as proved undeveloped. It will take substantial capital to drill our non-producing and undeveloped locations. Our estimate of proved reserves on December 31, 2025 assumes that we will need to spend significant development capital expenditures to develop these reserves. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.
If actual reserves are lower than anticipated, the financial condition and results of operations of the Company could be adversely affected.
The Company’s ability to achieve anticipated production levels depends on the accuracy of its reserve estimates, which are inherently uncertain. Actual reserves may differ materially from estimates due to future development timing, development expenditures, operating costs, and reservoir performance as well as commodity price factors. If actual reserves are lower than anticipated, the financial condition and results of operations of the Company could be adversely affected.
Approximately 181,093 net acres in the PRB are located on federal lands as of December 31, 2025, which are subject to administrative permitting requirements, current and potential federal legislation, regulation and orders and pending litigation that may limit or restrict oil and natural gas operations on federal lands.
At December 31, 2025, approximately 181,093 net acres in the PRB were on federal lands administered by the Bureau of Land Management. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, the advancement of presidential administrative priorities and government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the availability of federal leases or the granting and renewal of permits or other licenses, approvals or certificates required to conduct our operations. Delays in making federal acreage available for leasing by oil and gas operators or obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. Under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our interests on federal lands.
In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. For example, in 2022, two environmental advocacy groups filed suit against the U.S. Department of Interior and the BLM challenging certain lease sales by the BLM beginning in December of 2017 (the “BLM Litigation”). On January 17, 2025, a three-judge panel of the Ninth Circuit Court of Appeals upheld vacatur of various leases sold by the BLM, on grounds that the BLM violated the NEPA (defined herein) and the Federal Land Planning and Management Act when selling certain leases. It remains unclear whether parties involved in the BLM Litigation will seek en banc review of the decision. While the Company is not named in the BLM Litigation (as defendants, intervenors or otherwise), certain of the leases owned by the Company in the PRB covering approximately 82,804 acres (as of December 31, 2025) have been “placed in suspense” pending a ruling by the Ninth Circuit Court of Appeals in the BLM Litigation. It is possible that the Ninth Circuit Court of Appeals ruling could result in the cancellation of these leases. In addition, as part of the BLM Litigation, on September 13, 2024, the U.S. District Court for the District of Columbia issued a ruling temporarily enjoining further applications for permits to drill with respect to certain of the Company’s BLM leases, citing erroneous data that overstated the amount of available groundwater in the Converse County Oil and Gas Project’s (the “Project’s”) Environmental Impact Statement. This ruling had the effect of halting federal APD approvals within the area of the Project until the court “determines the appropriate final remedy” to correct the deficiency being alleged in the case. It is possible that the BLM’s review and ultimate approval of our APDs could be impacted by this federal court ruling. If the January 17, 2025 Ninth Circuit Court of Appeals decision remains final, or if a final judgment on any similar future litigation results in the cancellation of leases or otherwise restricts production of our oil, natural gas or NGLs assets, our financial condition, results of operations and cash flows could be materially and adversely affected; however, we could also receive the return of up to $79 million of total lease bonuses previously paid in certain circumstances, which would have a positive effect on working capital.
Our hedging activities may prevent us from fully benefiting from increases in crude oil, natural gas and NGLs prices and may expose us to other risks, including counterparty risk, and our future production may not be sufficiently protected from any declines in commodity prices by our existing or future hedging arrangements.
We use financial derivative instruments (primarily financial fixed price swaps and collar contracts) to hedge the impact of fluctuations in commodity prices on our results of operations and cash flows. In connection with the entry into the A&R Credit Agreement, the Company was 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. As of the date of this report, the Company currently has approximately 75% of its crude oil production hedged through November 2027 and approximately 51% hedged from December 2027 through November 2028, and ~75% of its natural gas production hedged through November 2027 and approximately 50% hedged from December 2027 through November 2028, at various prices.
Our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. Our hedges may in the future result in losses and reduce the amount of revenue we would otherwise obtain upon the sale of our oil and natural gas production and may also decrease our margins and net revenues.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for the relevant period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
To the extent that we have engaged, or in the future engage, in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in commodity prices above the prices established by our hedging contracts. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
In addition, depending on the type of derivative arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil and gas prices. It cannot be assumed that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in commodity prices.
Increases in the differential between the ceiling value for oil and natural gas prices set forth in our commodity derivative contracts and commodity derivative collar contracts is anticipated to affect our business, financial condition and results of operations.
For more information regarding our current derivative instruments see “Item 8 Financial Statements and Supplementary Data” – “Note 10 – Derivatives”.
Our current operations are concentrated in the states of New Mexico andMexico, Colorado, with future operations potentially extending intoand Wyoming. This concentration may increase the potential impact of many of the risks described in this Annual Report. For example, we may have greater exposure to regulatory actions impacting New Mexico, ColoradoColorado, and/or Wyoming, adverse weather and natural disasters in New Mexico, ColoradoColorado, and/or Wyoming, competition for equipment, services and materials available in, and access to infrastructure and markets in, these states.
We are not the operator on someall of our properties located in our D-J Basin and PRB Asset, and, as a result, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:
If we do not hedge our exposure to reductions in oil and natural gas prices, we may be subject to significant reductions in prices. Alternatively, we may use oil and natural gas price hedging contracts, which involve credit risk and may limit future revenues from price increases and result in significant fluctuations in our profitability.
In the event that we continue to choose not to hedge our exposure to reductions in oil and natural gas prices by purchasing futures and/or by using other hedging strategies, we may be subject to a significant reduction in prices which could have a material negative impact on our profitability. Alternatively, we may elect to use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.
Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. New Mexico, ColoradoColorado, and Wyoming, all have relatively arid climates and experience drought conditions from time to time and the U.S. Southwest is currently experiencing significant drought conditions which have reduced the flow of certain rivers and forced the reduction or reallocation of certain waterways and reservoirs. If we are unable to obtain water to use in our operations from local sources or dispose of or recycle water used in operations, or if the price of water or water disposal increases significantly, we may be unable to produce oil and natural gas economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows.
AApproximately substantial percentage50% of our Colorado andColorado, New Mexico properties,Mexico, and all of our Wyoming properties, are undeveloped; therefore, the risk associated with our success is greater than would be the case if the majority of such properties were categorized as proved developed producing.
Because aapproximately substantial percentage50% of our Colorado andColorado, New Mexico properties,Mexico, and all of our Wyoming properties, are undeveloped, we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.
Our operations in the Permian Basin in Chaves and Roosevelt Counties, New Mexico, and the D-J Basin in Weld and Morgan Counties, Colorado, and potentiallythe extendingPRB intoin Laramie County,and Campbell Counties, Wyoming, involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and therefore generate the highest possible returns. The additional risks that we face while drilling horizontally include, but are not limited to, the following:
The $1.1 million owed to us under a secured convertible promissory note due from Tilloo in the Milnesand Sale may not be repaid.
On November 9, 2023, pursuant to the terms of the Milnesand Sale, the Company entered into a five-year secured promissory note (the “Note”) with Tilloo, bearing interest at 10% per annum, with no payments due until January 8, 2025, and fully-amortized payments due monthly over the remaining four years of the term thereafter until maturity. The Note contains customary events of default and is secured by a lien over all the assets and capital shares of EOR Operating Company (“EOR”), our prior wholly-owned subsidiary which was sold to Tilloo, created under a Security Agreement, a Security Agreement (Pledge of Corporate Securities), and a Mortgage entered into by and between the Company and Tilloo. Tilloo failed to make the initial installment payment due under the Tilloo Note on January 8, 2025. The Company issued a notice of default under the Tilloo Note to Tilloo in mid-January 2025, and the Company intends to pursue all available avenues and remedies, including potential foreclosure under the security agreement and mortgages securing the secured obligation, to resolve these matters. However, Tilloo may not make any payments under the Note and the Company may not be able to recover amounts due under the Note. Furthermore, litigation relating to the repayment of the Note, if initiated, may take away time and resources that management would otherwise have spent on other matters, which may adversely affect our results of operations and ultimately the value of our common stock.
The requirements, restrictions and covenants in our RBL,A&R Credit Agreement, including interest payable thereunder, may restrict our ability to operate our business and might lead to a default under such agreement.
Borrowings under the RBLA&R Credit Agreement may be alternate base rate (“ABR”) loans or SOFR loans, at the election of the Company. Interest is payable quarterly for ABR loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at the forward-looking term rate based on the secured overnight financing rate as administered by the Federal Reserve Bank of New York (“SOFR”) for a one, three or six-month interest period plus an applicable margin ranging from 300 to 400 basis points, depending on the percentage of the borrowing base utilized, plus an additional 10 basis point credit spread adjustment (the “SOFR Rate”). ABR loans bear interest at a rate per annum equal to the greatest of: (i) the prime rate as publicly announced by Citibank; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted forward-looking term rate based on SOFR for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 200 to 300 basis points, depending on the percentage of the borrowing base utilized (the “ABR Rate”). The Company also pays a commitment fee on unused commitment amounts under its facility of 37.5 basis points or 50 basis points, depending on the percentage of the borrowing base utilized. The Company may repay any amounts borrowed under the RBLA&R Credit Agreement prior to the maturity date without any premium or penalty, and is required to repay certain portions of the amounts borrowed under the RBLA&R Credit Agreement upon the occurrence of certain events.
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.
The RBL includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Loan Parties from creating any indebtedness without the consent of the lenders, subject to certain exceptions, and requiring the Company to have a net leverage ratio (the ratio of (a) total net debt to (b) EBITDAX) of no less than 1.0 to 1.0 and a current ratio (the ratio of (i) consolidated current assets to (ii) consolidated current liabilities) of no less than 1.0 to 1.0. EBITDAX is defined as 'Earnings Before Interest, Taxes, Depreciation (or Depletion), Amortization, and Exploration Expense In addition, the RBLA&R Credit Agreement is subject to customary events of default for a facility of that size and type, including a change in control. If an event of default occurs and is continuing, the administrative agent may, with the consent of majority lenders, or shall, at the request of the majority lenders, accelerate any amounts outstanding and terminate lender commitments and declare the entire amount of obligations owed under the RBLA&R Credit Agreement immediately due and payable and take certain other actions provided for under the RBL.A&R Credit Agreement.
As a result of these requirements, covenants and limitations, we may not be able to respond to changes in business and economic conditions and to obtain additional financing, if needed, and we may be prevented from engaging in transactions that might otherwise be beneficial to us. The breach of any of these requirements or covenants could result in a default under the RBLA&R Credit Agreement or future credit facilities. Upon the occurrence of an event of default, the lenders could elect to declare all amounts outstanding under such RBLA&R Credit Agreement or future debt facilities, including accrued interest or other obligations, to be immediately due and payable. If amounts outstanding under such RBLA&R Credit Agreement or future debt facilities were to be accelerated, our assets might not be sufficient to repay in full that indebtedness and our other indebtedness.
Management's Discussion & Analysis (MD&A)
New heading “Net (Loss) Income”
Removed heading “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.”
Largest changes
“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.”see in full comparison
“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. …”see in full comparison
“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. …”see in full comparison
“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. …”see in full comparison
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 oursee in full comparison20252026 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 ourreserve-basedA&RlendingCreditfacility (“RBL”)Agreement with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of$20$120 million and an aggregate maximum revolving credit amount of $250 million (of whichnone$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) equity infusions or loans (which may be convertible) made available from Dr. Simon G. 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 toa Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the“LeadATMAgent”),OfferingandnotedA.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),above, and (viv) 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 of2025.2026.
“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”). …”see in full comparison
Full comparison: every changed paragraph (53)
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.
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.”
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.
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 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 BasinBasin, Powder River Basin, and Permian Basin Assets, is contained under “Part 1” — “Item 1. Business” above.
Our estimated net proved crude oil and natural gas reserves at December 31, 20242025 and 20232024 were approximately 18.132.1 million barrels of oil equivalent (“MMBoe”) and 17.018.1 MMBoe, respectively. The 1.114.0 MMBoe increase was primarily due to increase in proved developed producing reserves related to the additionacquisition of properties in the D-J and Powder River Basin, and proved undeveloped reserves related to the acquisition of properties in ourthe D-J Basin Asset as a result of increased activity around our acreage and favorable pricing.Basin.
Using the average monthly crude oil price of $75.48$65.34 per barrel (“Bbl”) and natural gas price of $2.13$3.39 per thousand cubic feet (“Mcf”) for the twelve months ended December 31, 2024,2025, our estimated discounted future net cash flow (“PV-10”) for our proved reserves was approximately $178.9$357.7 million, of which approximately $104.3$100.2 million are proved undeveloped reserves. Total reserve value at December 31, 2024,2025, represents aan decreaseincrease of approximately $52.8$178.8 million or 23%100% from approximately $231.7$178.9 million a year earlier using the same SEC pricing and reserves methodology. The decreaseincrease is primarily attributable to commoditythe pricing,increase asin proved reserves volumes related to the averagerelated SEC pricing for 2024, noted above, was lower thanto the 2023 average pricingacquisition of $78.22properties perin Bblthe forD-J crude oilBasin and $2.64Powder perRiver McfBasin forfrom naturalthe gas.Mergers.
During the year ended December 31, 2024,2025, our net crude oil, natural gas, and NGLs sales volumes increased to 671,796910,068 Bbls, or 1,8352,494 barrels of oil per day (“Bopd”), from 520,886671,796 Bbls, or 1,4271,835 Bopd, a 29%36% increase over the previous fiscal year. The increaserise in production volume is relatedlargely todriven by our participationOctober 2025 Mergers, resulting in 24an newadditional non-operated303 wells (11Mboe of whichproduction occurredduring in the latter four months of 2024) in the D-J BasinNovember and theDecember drilling2025 and completion of three operated wells with a third-party in the Permian Basin in the latter part of Q1 2024combined (see additionalfurther detaildetails below).
*see “Item 8. Financial Statements and Supplementary Data” - “Note 6 – Merger Acquisition and Note 7 - Oil and Gas Properties”.
The following discussion and analysis of the results of operations for each of the two fiscal years in the years ended December 31, 20242025 and 20232024 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”).
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).
Total crude oil, natural gas and NGL revenues for the year ended December 31, 2024,2025, increased $8.8$6.2 million, or 28%,16%, to $39.6$45.8 million, compared to $30.8$39.6 million for the same period a year ago, due to a favorable volume variance of $8.8$12.2 million.million, Thereoffset wasby aan negligibleunfavorable price variance overof $6.0 million, due primarily to the periods.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 participationOctober in2025 24Mergers newwhereby non-operatedwe wellsadded ina total 303 Mboe of oil and gas production sales for the D-Jmonths Basinof November and theDecember drilling2025 and completion of three operated wells in the Permian Basin.combined.
* Includes severance, ad valorem taxes, workover adjustments and assessment and marketinggathering, transportation and processing costs.
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 again 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.
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.
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.
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.
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.
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.
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.
The primary sources of cash for the Company during the year ended December 31, 20242025 were from $39.6a 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.
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”).
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. 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”). 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 CompanyATM hasOffering anwas ongoingmade $8.0pursuant millionto offeringthe terms of securitiesthat incertain anDecember 20, 2024, Sales Agreement (the “atSales Agreement”), entered into with Roth Capital Partners, LLC (the “Lead Agent”) and A.G.P./Alliance Global Partners (“AGP”, and collectively with the marketLead offeringAgent, the “Agents”), pursuant to which the Company may sell securities from time to time (thein an “ATM Offering”). The ATM Offering was made pursuant toat the termsmarket of a December 20, 2024, Sales Agreement (the “Sales Agreementoffering”) with Roth Capital Partners, LLC and A.G.P./Alliance Global Partners.. 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 20252026 are estimated at the time of this Annual Reportfiling to range between $27$16 million to $33$20 million,million. includingThis $24.5estimate includes a range of $6 million to $30.5$7 million for drilling and completion costs on our Permian Basin and D-J Basin Assets (of which approximately $3 million is carry over from our 2025 program) and approximately $2.5$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) purchases,to rod pump conversions, compression optimization projects, recompletions, and well cleanouts,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 70% to 75%90% of our expected capital expenditures for 20252026 will be allocated to development in the D-J Basin underand our10% Februarywill 2025be jointallocated developmentto agreementthe enteredPowder into with a large private equity-backed D-J Basin operatorRiver and ourPermian ParticipationBasins. AgreementThese andestimates Area of Mutual Interest (AMI) entered into in August 2024 with a private operator. This estimate doesdo 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 Permian Asset to ouroperated D-J BasinBasin, Asset,Powder orRiver viceBasin, versa, as ourand Permian AssetBasin is 100% operated and nearly 100% held by production (“HBP”),assets, allowing for flexibility ofon timing onof development. Our 20252026 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 20252026 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-basedA&R lendingCredit facility (“RBL”)Agreement with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $20$120 million and an aggregate maximum revolving credit amount of $250 million (of which none$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) equity infusions or loans (which may be convertible) made available from Dr. Simon G. 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 “LeadATM Agent”),Offering andnoted 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),above, and (viv) 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 2025.2026.
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 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 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.
Cash used in investing activities. Net cash used in investing activities decreasedincreased by $8.9$106.3 million for the current year’s period, when compared to the prior year’s period, primarily due to decreased cash outlays from our capitalMergers spending(see relating“Item to8. ourFinancial drillingStatements and completionSupplementary activities.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.
Cash financing activities. There were no cash flow financing activities in the current or prior period.
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, lossimpairment of oil and gas properties, gain on sale of oil and gas properties, net, and gain on sale of fixed assets.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):
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 IssuedAdopted 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. ThisThe Company adopted this ASU will be effective for the annual period endingon December 31, 2025.2025 and has reflected the required disclosures in the accompanying notes to the consolidated financial statements. The CompanyASU ishad currentlyno evaluatingimpact on the timingCompany’s andconsolidated impactsbalance sheets, consolidated statements of adoptionoperations or consolidated statements of thiscash ASU.flows.
What changed in the latest 10-Q
Risk Factors
Largest changes
We use financial derivative instruments (primarily financial fixed price swaps and collar contracts) to hedge the impact of fluctuations in commodity prices on our results of operations and cash flows. In connection with the entry into the A&R Credit Agreement, the Company was 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.see in full comparisonAs of the date of this report, the Company currently has approximately 75% of its crude oil production hedged through November 2027 and approximately 51% hedged from December 2027 through November 2028, and ~75% of its natural gas production hedged through November 2027 and approximately 50% hedged from December 2027 through November 2028, at various prices.
“As of the date of this report, the Company currently has approximately 61% of our forecasted production on a BOE basis hedged for the second half of 2026, 58% hedged for 2027 and 39% hedged for 2028.”see in full comparison
In addition to commodity price volatility, our asset base is subject to the risk of lease expirations, which may result in the loss of leasehold interests and associated capitalized costs if we are unable to meet drilling commitments or obtain extensions. In our D-J Basin asset, 16,138 total net acressee in full comparisonarewere scheduled to expire during 2026, of which 3,310 net acres expired during the first half of 2026, with an additional 2,133 and 638 net acres expiring in 2027 and 2028, respectively, and 8,081 net acres thereafter, in each case net to our direct ownership interest, if we do not satisfy applicable drilling or extension requirements. In the PRB, 4,822 total net acresarewere set to expire in 2026, of which 720 net acres expired during the first half of 2026, with 34,999 and 15,828 net acres expiring in 2027 and 2028, respectively. In the Permian Basin asset, approximately 200 net acres are scheduled to expire in 2026 (net to our direct ownership interest only). If these leases expire without being developed or extended, we may be required to write off the associated unproved property costs, which could result in material non-cash charges.
For the three and six months endedsee in full comparisonMarchJune31,30, 2026, the Company had a net gain on derivative contracts of $5.0 million and a net loss on derivative contracts of$31.3$26.3million.million, respectively. Our hedging activities have in the pastexpose,exposed, and may in the future expose, us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. Our hedges have in the past and may in the future result in losses and reduce the amount of revenue we would otherwise obtain upon the sale of our oil and natural gas production and may also decrease our margins and net revenues.
Full comparison: every changed paragraph (5)
We use financial derivative instruments (primarily financial fixed price swaps and collar contracts) to hedge the impact of fluctuations in commodity prices on our results of operations and cash flows. In connection with the entry into the A&R Credit Agreement, the Company was 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. As of the date of this report, the Company currently has approximately 75% of its crude oil production hedged through November 2027 and approximately 51% hedged from December 2027 through November 2028, and ~75% of its natural gas production hedged through November 2027 and approximately 50% hedged from December 2027 through November 2028, at various prices.
As of the date of this report, the Company currently has approximately 61% of our forecasted production on a BOE basis hedged for the second half of 2026, 58% hedged for 2027 and 39% hedged for 2028.
For the three and six months ended MarchJune 31,30, 2026, the Company had a net gain on derivative contracts of $5.0 million and a net loss on derivative contracts of $31.3$26.3 million.million, respectively. Our hedging activities have in the past expose,exposed, and may in the future expose, us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. Our hedges have in the past and may in the future result in losses and reduce the amount of revenue we would otherwise obtain upon the sale of our oil and natural gas production and may also decrease our margins and net revenues.
To the extent that we have engaged, or in the future engage, in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in commodity prices above the prices established by our hedging contracts, similar to what occurred during the threesix months ended MarchJune 31,30, 2026. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.
In addition to commodity price volatility, our asset base is subject to the risk of lease expirations, which may result in the loss of leasehold interests and associated capitalized costs if we are unable to meet drilling commitments or obtain extensions. In our D-J Basin asset, 16,138 total net acres arewere scheduled to expire during 2026, of which 3,310 net acres expired during the first half of 2026, with an additional 2,133 and 638 net acres expiring in 2027 and 2028, respectively, and 8,081 net acres thereafter, in each case net to our direct ownership interest, if we do not satisfy applicable drilling or extension requirements. In the PRB, 4,822 total net acres arewere set to expire in 2026, of which 720 net acres expired during the first half of 2026, with 34,999 and 15,828 net acres expiring in 2027 and 2028, respectively. In the Permian Basin asset, approximately 200 net acres are scheduled to expire in 2026 (net to our direct ownership interest only). If these leases expire without being developed or extended, we may be required to write off the associated unproved property costs, which could result in material non-cash charges.
Management's Discussion & Analysis (MD&A)
New heading “Six Months Ended June 30, 2026, vs. Six Months Ended June 30, 2025”
New heading “Operating Expenses and Other Income”
Largest changes
“Six Months Ended June 30, 2026, vs. Six Months Ended June 30, 2025”see in full comparison
“We reported a net loss for the three-month period ended March 31, 2026, of $25.6 million, or ($3.28) per common share, compared to net income of $0.1 million, or $0.03 per share, for the three-month period ended March 31, 2025. Although revenues increased by $31.5 million in the current period compared to the prior period, net income decreased by $26.6 million. …”see in full comparison
“Cash flows provided by operating activities. Net cash provided by operating activities increased by $4.6 million for the current year’s period, when compared to the prior year’s period, primarily due to a decrease in net income of $26.5 million, which was offset by a $31.3 million net loss on derivative contracts and a $9.1 million increase in depreciation, depletion and amortization an $1.4 million increase in the impairment of oil and gas properties during the current period offset by a $10.7 million net decrease to our other components of working capital (predominantly from our drilling …”see in full comparison
“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.”see in full comparison
“Asset Retirement Obligations. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company will record a liability (an asset retirement obligation or “ARO”) on its consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. …”see in full comparison
Full comparison: every changed paragraph (55)
Certain capitalized terms used below but not otherwise defined, are defined in, and shall be read along with the meanings given to such terms in, the notes to the unaudited financial statements of the Company for the three and six months ended MarchJune 31,30, 2026, above.
As of MarchJune 31,30, 2026, we held approximately 89.78488,605 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 MarchJune 31,30, 2026, the Company held approximately 202,100202,380 net acres in the Powder River Basin, predominantly located in Campbell County, Wyoming, through its wholly-owned subsidiary Century Oil and Gas Sub-Holdings, 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 MarchJune 31,30, 2026, we held approximately 14,505 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.”
As of MarchJune 31,30, 2026, we held interests in 184 gross (79.4 net) wells, consisting of 180 producing wells, three saltwater disposal wells, and one 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 consisting of 34 producing wells, two injection wells, and two saltwater disposal wells.
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 remainder 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) public or private debt or equity financings, including up to $7.6 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 “Liquidity and Capital Resources—Financing” (under which we have sold 24,498 shares of common stock to date at a sales prices ranging between $14.32 to $16.02 per share), and (iv) funding through credit or loan facilities, including under the Company’s A&R Credit Agreement with Citibank, N.A., as administrative agent, which currently provides for an initiala borrowing base of $120$125 million and an aggregate maximum revolving credit amount of $250 million (of which $98$85 million has been drawn down by the Company to date), as discussed in greater detail below under “Amended and Restated Credit Agreement”. In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2026.
In February 2025, the Company entered into a Joint Development Agreement with a large, Denver, Colorado-based private equity-backed D-J Basin exploration and production (E&P) Company with extensive operational experience (the “Operator”), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company’s Roth and Amber drilling spacing units (DSUs) located in Weld County, Colorado, with the Operator paying to the Company $1.7 million, the Company agreeing to amend the Company’s existing Roth and Amber DSUs to increase each to 1,600 acres and transferring operatorship of the DSUs to the Operator, and the parties agreeing to jointly participate in the development of the Roth and Amber DSUs. The Roth wells were drilled and completed in the fourth quarter of 2025. The Operator had until May 10, 2026, to make an election to acquire up to 50% of the Company’s working interest in the Amber DSU at an acquisition price of approximately $2.5 million,million whichbut electiondid datenot themake Companythis agreed to extend through May 18, 2026.election.
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 borrowing base is scheduled to be redetermined semiannually on or about April 1 and October 1 of each calendar year, commencing on April 1, 2026, and is subject to additional adjustments from time to time, includingincluding, for certain asset sales, elimination or reduction of hedge positions and title defects.
On December 2, 2025, the parties to the A&R Credit Agreement entered into a First Amendment to Credit Agreement, which amended the A&R Credit Agreement to add an additional lender and re-allocate commitments among the lender group, which amendment was deemed immaterial by the Company, as there were no changes to the maturity date, the borrowing base, or any other material items.Company.
On May 19, 2026, the parties to the A&R Credit Agreement entered into a Third Amendment to Credit Agreement to increase the borrowing base and elected commitment amount from $120 million to $125 million. The redetermination of the borrowing base pursuant to the Third Amendment constituted the redetermination originally scheduled for on or about December 1, 2025, with the next redetermination scheduled to occur on or about July 1, 2026.
In connection with the closing of the Mergers, the Company drew $87 million under the A&R Credit Agreement. The Company subsequently borrowed an additional $6.0 million on January 8, 2026 and $5.0 million on February 5, 2026. The proceeds from these borrowings were used to fund the Company’s participation in certain non-operated well operations and to pay other Company obligations. ADuring totalQ2 2026, the Company paid $13 million, resulting in an outstanding balance of $98$85.0 million is currently outstanding under the A&R Credit Agreement as of theJune date30, of this filing.2026.
The following discussion and analysis of the results of operations for the three-monththree and six-month periods ended MarchJune 31,30, 2026, and 2025, should be read in conjunction with our consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. The majority of the numbers presented below are rounded numbers and should be considered as approximate.
Three Months Ended MarchJune 31,30, 2026, vs. Three Months Ended MarchJune 31,30, 2025
We reported net income for the three-month period ended June 30, 2026, of $17.5 million, or $1.31 per common share, compared to a net loss of $1.7 million, or ($0.37) per common share, for the three-month period ended June 30, 2025. The $19.1 million increase in net income is primarily attributable to a $17.6 million increase in operating income associated with the October 2025 Mergers. Furthermore, during the three months ended June 30, 2026, the Company recorded $5.0 million in income on derivative contracts (both realized and unrealized) as commodity pricing decreased temporarily as of June 30, 2026 from previous highs at March 31, 2026. Offsetting these increases to net income was $2.0 million in interest expense recorded during the three months ended June 30, 2026. Prior to the Company’s Mergers in October 2025, the Company had no outstanding debt or hedge positions as of or for the three months ended June 30, 2025.
We reported a net loss for the three-month period ended March 31, 2026, of $25.6 million, or ($3.28) per common share, compared to net income of $0.1 million, or $0.03 per share, for the three-month period ended March 31, 2025. Although revenues increased by $31.5 million in the current period compared to the prior period, net income decreased by $26.6 million. This decline was primarily driven by a net loss of $31.3 million on derivative contracts (both realized and unrealized), resulting from the recent and substantial increase in commodity prices in relation to the Company’s hedge positions. Additional factors contributing to the decrease include $2.0 million in interest expense and $24.9 million in total operating expenses, which includes a $1.6 million impairment of oil and gas properties (each discussed in more detail below) combined with income tax benefit of $868,000 (see Note 16 – Income Taxes, in the notes to the consolidated financial statements above under “Part I – Financial Information—Item 1. Financial Statements”).. Prior to the Company’s Mergers in October 2025, the Company had no outstanding debt or hedge positions during the three-month period ended March 31, 2025.
Total crude oil, natural gas and NGL revenues for the three-month period ended MarchJune 31,30, 2026, increased $31.5$39.1 million, or 360%,561%, to $40.2$46.1 million, compared to $8.7$7.0 million for the same period a year ago,ago. dueOf the total increase in revenues, $35.8 million is attributable to aincreased favorablesales volumevolumes varianceand of$3.3 $32.2million million,is offset by an unfavorable price variance of $0.7 million, due primarilyattributable to theincreased average sales price for natural gas and liquids realized by the Company decreasingpricing compared to the prior period. The increase in production volume is related to our October 2025 Mergers whereby we added a total of 432 thousand barrels of oil equivalent (Mboe) of additional oil and gas production sales for the current period.
Lease operating expenses. Lease operating expenses increased by $12.9$13.6 million for the periodthree months ended MarchJune 31,30, 2026, primarily due to the October 2025 Mergers. Acquired properties contributed $7.2$6.9 million of direct lease operating expenses and $4.8$5.0 million of other operating costs, along with $0.9$1.7 million of higher variable expenses associated with increased legacy production volumes.
Depreciation, depletion, amortization and accretion. Increased by $9.1$6.3 million for the periodthree months ended MarchJune 31,30, 2026, compared to the prior period, primarily due to the production increase noted above, which is primarily attributed to inclusion of the Acquired Companies.
Impairment of oil and gas properties. The Company recorded an impairment of oil and gas properties of $1.6$0.8 million and $0.2$0.5 inmillion during the periodsthree months ended MarchJune 31,30, 2026 and 2025, respectively,respectively. The impairments related to the expiration of certain leases representing 3,6602,002 and 232776 net acres, respectively, in the D-J Basin, that it allowed to expire or currently has no plans to drill prior to expiration.
General and administrative expenses (excluding share-based compensation). General and administrative expenses (excluding share-based compensation) increased by $1.5$1.8 million for the periodthree months ended MarchJune 31,30, 2026, compared to the prior period, primarily due to additional payroll expenses compared to the prior period,associated with the addition of 12 employees added in connection with the Mergers,Mergers and higher legal and audit fees due to the growth of the Company period over period.
Share-Based Compensation. Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, nominallyslightly increaseddecreased when comparing periods. Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations.
Net loss on derivative contracts. For the three months ended June 30, 2026, the Company recorded net income of $5.0 million from its derivative contracts. Although the Company recorded $8.1 million in realized losses during the three months ended June 30, 2026, this loss was offset by an unrealized gain on derivative contracts of $13.1 million. primarily due to the decrease in commodity pricing from March 31, 2026 to June 30, 2026 related to unsettled periods. There were no derivative contracts in the prior period.
Net loss on derivative contracts. For the period ended March 31, 2026, the Company recorded a realized loss of $3.4 million from derivative contract settlements, primarily due to crude oil prices at settlement exceeding the fixed prices specified in the contracts. The Company also recorded an unrealized loss of $27.9 million related to the mark-to-market valuation of outstanding derivative contracts, driven by increases in commodity prices during the latter part of the first quarter of 2026. This non-cash charge was driven by a sustained upward shift in the forward crude oil price curve during the latter part of the first quarter of 2026, which increased the estimated fair value of the Company's net liability position under these contracts. There were no derivative contracts in the prior period.
Interest expense. The Company recognized $2.0 million in interest expense in the current period compared to no interest expense in the prior period due,as toa result of the Company utilizing its credit facility beginning in October 2025. Interest expense for the current period consisted of $1.8 million ofin interest incurred under the A&R Credit Agreement (discussed above) and $0.2 million related to the amortization of deferred financing costs. No interest expense or amortization of deferred financing costs were recorded in the prior period.
Six Months Ended June 30, 2026, vs. Six Months Ended June 30, 2025
We reported a net loss for the six month period ended June 30, 2026, of $8.2 million, or ($0.77) per common share, compared to a net loss of $1.5 million, or ($0.34) per common share, for the six months ended June 30, 2025. Although operating income increased by $24.2 million in the current period compared to the prior period, primarily the result of the October 2025 Mergers, net income decreased by $6.6 million. The decline was primarily driven by a net loss of $26.3 million on derivative contracts (both realized and unrealized), resulting from the recent and substantial increase in commodity prices in relation to the Company’s hedge positions. Additionally, the Company recorded $4.0 million in interest expense during the six months ended June 30, 2026. Prior to the Company’s Mergers in October 2025, the Company had no outstanding debt or hedge positions as of or for the six months ended June 30, 2025.
Net Revenues
The following table sets forth the operating results and production data for the periods indicated:
Total crude oil, natural gas and NGL revenues for the six-month period ended June 30, 2026, increased $70.6 million, or 450%, to $86.3 million, compared to $15.7 million for the same period a year ago. Of the total increase in revenues, $68.3 million is attributable to increased sales volumes and $2.3 million is attributable to increased pricing compared to prior period. The increase in production volume is related to our October 2025 Mergers.
Operating Expenses and Other Income
The following table summarizes our production costs and operating expenses for the periods indicated (in thousands):
* Includes severance, ad valorem taxes, assessment and gathering, transportation and processing costs.
Lease operating expenses. Lease operating expenses increased by $26.6 million for the six months ended June 30, 2026, primarily due to the October 2025 Mergers. Acquired properties contributed $14.3 million of direct lease operating expenses and $9.8 million of other operating costs, along with $2.5 million of higher variable expenses associated with increased legacy production volumes.
Depreciation, depletion, amortization and accretion. Increased by $15.4 million for the six months ended June 30, 2026, compared to the prior period, primarily due to the production increase noted above, which is attributed to inclusion of the Acquired Companies.
Impairment of oil and gas properties. The Company recorded an impairment of oil and gas properties of $2.4 million and $0.7 million during the six months ended June 30, 2026 and 2025, respectively, related to the expiration of certain leases representing 5,662 and 776 net acres, respectively, in the D-J Basin, that it allowed to expire or currently has no plans to drill prior to expiration.
General and administrative expenses (excluding share-based compensation). General and administrative expenses (excluding share-based compensation) increased by $3.3 million for the six months ended June 30, 2026, compared to the prior period, primarily due to additional payroll expenses compared to the prior period, with the addition of 12 employees added in connection with the Mergers, and higher legal and audit fees due to the growth of the Company period over period.
Share-Based Compensation. Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, slightly decreased when comparing periods.
Net loss on derivative contracts. For the six months ended June 30, 2026, the Company recorded a net loss of $26.3 million from it derivative contracts. During this period, the Company recorded $11.5 million in realized losses for its settled contracts and an unrealized loss of $14.8 million in unrealized losses for its unsettled contracts. Both losses were driven by the increases in commodity pricing during the first half of 2026 compared to prior periods. There were no derivative contracts in the prior period.
Interest expense. The Company recognized $4.0 million in interest expense in the current period compared to no interest expense in the prior period as a result of the Company utilizing its credit facility beginning in October 2025. Interest expense for the current period consisted of $3.6 million of interest under the A&R Credit Agreement (discussed above) and $0.4 million related to the amortization of deferred financing costs. No interest expense or amortization of deferred financing costs were recorded in the prior period.
Interest Income and Other Income. Includes interest earned from our interest-bearing cash accounts which modestly decreased due to increased operational spending in the current period compared to the prior period. Other income also decreased slightly period over period.
The primary sources of cash for the Company during the three-monthsix-month period ended MarchJune 31,30, 2026 were from $40.2$86.3 million in sales of crude oil, natural gas and NGLsNGLs. As of June 30, 2026, the Company has $12.1 million in cash and drawdownsrestricted totalingcash $11.0and availability of $40 million fromunder ourthe A&R Creditcredit Agreement. The primary uses of cash were funds used for drilling, completion and operating costs.
At MarchJune 31,30, 2026, the Company’s total current liabilities of $62.9$50.7 million exceeded its total current assets of $42.5$39.8 million, resulting in a working capital deficit of $20.4$10.9 million. At December 31, 2025, total current liabilities of $64.5 million exceeded total current assets of $37.8 million, resulting in a working capital deficit of $26.7 million. The $6.3$15.8 million decrease in the working capital deficit was primarily driven by a reduction in capital payables and accrued expenses following the completion of certain drilling programs with third-party partners during the period. This improvement was coupled with an increase in accounts receivable and cash balances from initial production sales related to the applicable wells.
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 MarchJune 31,30, 2026, a total of $7.6 million is available for future sales of common stock under the ATM Offering.
Our expected net capital expenditures for 2026 are discussed above under “Strategy”. 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 initiala borrowing base of $120$125 million and an aggregate maximum revolving credit amount of $250 million (of which $98$85 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.
Cash flows provided by operating activities. Net cash provided by operating activities increased by $4.6 million for the current year’s period, when compared to the prior year’s period, primarily due to a decrease in net income of $26.5 million, which was offset by a $31.3 million net loss on derivative contracts and a $9.1 million increase in depreciation, depletion and amortization an $1.4 million increase in the impairment of oil and gas properties during the current period offset by a $10.7 million net decrease to our other components of working capital (predominantly from our drilling and completion activities).
Cash flows (used in) provided by investingoperating activities. Net cash usedprovided inby investingoperating activities increased by $17.1$20.4 million for the current year’s period, when compared to the prior year’s period, primarily due to increasedan increase in operating income of $24.2 million, which was partially offset by a $7.8 million in cash outlayspaid fromfor ourderivative capitalsettlements spendingduring relatingthe tofirst ourhalf drillingof and completion activities.2026.
Cash flows (used in) provided by investing activities. Net cash used in investing activities increased by $17.0 million for the current year’s period, when compared to the prior year’s period, primarily due to increased cash outlays from our capital spending relating to our drilling and completion activities.
Cash flows (used in) provided by financing activities. ConsistedNet cash used in financing activities during the six months ended June 30, 2026 consisted of ana $11.0net repayment of $2 million drawdown on our credit facility and nominal fees related to our reverse stock split.facility. There were no significant cash flows from financing activities in the prior period.
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,compensation (non-cash), merger acquisition costs, impairment of oil and gas properties and netunrealized gain (loss) on derivative contracts. 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):
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.
Asset Retirement Obligations. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company will record a liability (an asset retirement obligation or “ARO”) on its consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the capitalized costs are depreciated on a unit-of-production basis over the estimated proved developed reserves. Both the accretion and the depreciation will be included in depreciation, depletion and amortization expense on our consolidated statements of operations.
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.
Derivative Instruments. The Company may periodically enter into derivative contracts to manage its exposure to commodity risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company chose not to elect hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.
PED insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 1 Form 4 filing (1 insider, 2 trade dates, 20,000 shares, about $288.8K) and open-market sales in 2 filings (1 insider, 4 trade dates, 29,057 shares, about $405.2K). Net open-market shares: -9,057 (purchases minus sales); net value about -$116.4K.Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-08-19 | Clark Moore |
Open-market sale | 1,218 | $12.37 | $15.1K |
| 2026-08-18 | Clark Moore |
Open-market sale | 5,277 | $12.53 | $66.1K |
| 2026-08-17 | Clark Moore |
Open-market sale | 3,765 | $12.81 | $48.2K |
| 2026-08-12 | Howie John K |
Grant/award | 1,111 | $11.25 | $12.5K |
| 2026-06-30 | Clark Moore |
Open-market sale | 18,797 | $14.67 | $275.8K |
| 2026-05-26 | Willsher Martyn |
Open-market purchase | 13,428 | $14.29 | $191.9K |
| 2026-05-22 | Willsher Martyn |
Open-market purchase | 6,572 | $14.74 | $96.9K |
| 2026-04-30 | Howie John K |
Grant/award | 782 | $15.98 | $12.5K |
Well-known investors holding PED (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Millennium Management (Israel Englander) | 2026-06-30 | 20,340 | $325.4K | — | Sold out |