PEDEVCO CORP 10-K

ITEM 1. BUSINESS. History We were originally incorporated in September 2000 as Rocker & Spike Entertainment, Inc. In January 2001 we changed our name to Reconstruction Data Group, Inc., and in April 2003 we changed our name to Verdisys, Inc. and were engaged in the business of providing satellite services to agribusiness. In June 2005, we changed our name to Blast Energy Services, Inc. (“ Blast ”) to reflect our new focus on the energy services business, and in 2010 we changed the direction of the Company to focus on the acquisition of oil and gas producing properties. On July 27, 2012, we acquired, through a reverse acquisition, Pacific Energy Development Corp., a privately held Nevada corporation, which we refer to as Pacific Energy Development. As described below, pursuant to the acquisition, the stockholders of Pacific Energy Development gained control of approximately 95% of the then voting securities of our company. Since the transaction resulted in a change of control, Pacific Energy Development was the acquirer for accounting purposes. In connection with the merger, which we refer to as the Pacific Energy Development merger, Pacific Energy Development became our wholly-owned subsidiary and we changed our name from Blast Energy Services, Inc. to PEDEVCO Corp. Following the merger, we refocused our business plan on the acquisition, exploration, development and production of oil and natural gas resources in the United States. As discussed in greater detail below under “ Business Strategy—Merger Agreement ”, on October 31, 2025, we entered into an Agreement and Plan of Merger (the “ Merger Agreement ”), between the Company, NP Merger Sub, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company (“ First Merger Sub ”), COG Merger Sub, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company (“ Second Merger Sub ,” and together with First Merger Sub, the “ Merger Subs ”), North Peak Oil & Gas, LLC, a Delaware limited liability company (“ NPOG ”), Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company (“ COG ,” and together with NPOG, the “ Acquired Companies ”), and, solely for purposes of the specified provisions therein, North Peak Oil & Gas Holdings, LLC, a Delaware limited partnership (“ North Peak ”). Pursuant to the Merger Agreement, on October 31, 2025, (a) First Merger Sub merged with and into NPOG, with NPOG being the surviving entity and a wholly-owned subsidiary of the Company and (b) Second Merger Sub merged with and into COG, with COG being the surviving entity and a wholly-owned subsidiary of the Company (the “ Mergers ”). Our corporate headquarters are located in approximately 5,200 square feet of office space at 575 N. Dairy Ashford, Suite 210, Houston, Texas 77079. We lease that space pursuant to a lease that expires in February 2027. Business Operations Overview We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies. Our current properties are located in the Denver-Julesberg Basin (“ D-J Basin ”) in Colorado and Wyoming, 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 (the “ 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 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. 10 Table of Contents 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 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 consisting of 34 producing wells, two injection wells, and two saltwater disposal wells. Business Strategy We believe that horizontal development and exploitation of conventional and unconventional oil and gas assets in the Rockies region, including the D-J and Powder River Basins, and the Permian Basin, represent among the most economic oil and natural gas plays in the U.S. We plan to optimize our existing assets and opportunistically seek additional acreage proximate to our currently held core acreage, as well as target other acquisitions in the Rockies region that fit our acquisition criteria. We believe there is a significant opportunity to build a leading oil and gas company in the Rockies region through both organic growth and acquisitions on terms that are more attractive than what we see in other oil and gas producing basins. Specifically, we seek to increase stockholder value through the following strategies: · Grow production, cash flow and reserves by developing our operated drilling inventory and participating opportunistically in non-operated projects. We believe our extensive inventory of drilling locations in the D-J Basin, Powder River Basin, and Permian Basin, combined with our operating expertise, will enable us to continue to deliver accretive production, cash flow and reserves growth. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base. · Apply modern drilling and completion techniques and technologies. We own and intend to acquire additional properties that have been historically underdeveloped and underexploited. We believe our attention to detail and application of the latest industry advances in horizontal drilling, completions design, frac intensity and locally optimal frac fluids will allow us to successfully develop our properties. · Optimization of development plans, well density and configuration. We own properties that are located in oil and gas producing basins that are geologically well defined, characterized by widespread vertical and horizontal development and geological well control. We utilize the extensive geological, petrophysical and production data of such properties to confirm optimal development plans, well spacing and configuration using modern reservoir evaluation methodologies. · Maintain a high degree of operational control and/or form partnerships which allow for a high degree of control over non-operated properties. We believe that by retaining operational control and/or by forming partnerships which require consent and input by all partners in major development projects, we can efficiently manage the timing and amount of our capital expenditures and operating costs, and thus key in on the optimal drilling and completions strategies, which we believe will generate higher recoveries and greater rates of return per well. · Leverage extensive deal flow, technical and operational experience to evaluate and execute accretive acquisition opportunities. Our management and technical teams have an extensive track record of forming, buying, building and selling oil and gas businesses. We also have significant expertise in successfully sourcing, evaluating and executing acquisition opportunities. We believe our understanding of the business, financial, geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acquisitions and leasing opportunities in order to grow our reserve base and maximize stockholder value. · Preserve financial flexibility to pursue organic and external growth opportunities. We intend to maintain a disciplined financial profile in order to provide flexibility across various commodity and market cycles. 11 Table of Contents Our strategy is to be the operator and/or a significant working interest owner, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan. In areas we deem highly economic and do not have a high enough working interest to serve as operator, we seek to participate in projects if returns match or exceed other projects in our portfolio. Due to the fragmented nature of acreage positions in some of our holdings, our ownership interest does not always allow us to serve as the operator. Our net capital expenditures for 2026 are estimated at the time of this filing to range between $16 million to $20 million. This estimate includes a range of $6 million to $7 million for drilling and completion costs on our D-J Basin Assets (of which approximately $3 million is carry over from our 2025 program) and approximately $10 million to $13 million in estimated capital expenditures for optimization projects on the newly acquired assets from the Mergers. These optimization projects include jet pump to rod pump or gas lift conversions, electronic submersible pump (ESP) to rod pump conversions, compression optimization projects, recompletions, and well cleanouts that are expected to materially lower lease operating expenses on our operated assets going forward. Other minor capital expenditures included in these figures are leasing, facilities, remediation and other miscellaneous capital expenses. We anticipate that approximately 90% of our expected capital expenditures for 2026 will be allocated to the D-J Basin and 10% will be allocated collectively to the Powder River and Permian Basin. These estimates do not include any expenditures for acquisitions or other projects that may arise but are not currently anticipated. We are evaluating future development plans for late 2026 and 2027, as we integrate the assets and operations acquired in the Mergers and work to execute the near-term optimization program outlined above. We periodically review our capital expenditures and adjust our capital forecasts and allocations based on liquidity, drilling results, leasehold acquisition opportunities, partner non-consents, proposals from third party operators, and commodity prices, while prioritizing our financial strength and liquidity (see “ Part I ” – “ Item 1A. Risk Factors ”). We plan to continue to evaluate D-J Basin non-operated well proposals as received from third party operators and participate in those we deem most economic and prospective. If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to expand our capital program or move capital from our operated D-J Basin, Powder River Basin, and Permian Basin assets, allowing for flexibility on timing of development. Our 2026 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity. We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund the 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 provides for an initial borrowing base of $120 million and an aggregate maximum revolving credit amount of $250 million (of which $98 million has been drawn down by the Company to date), as discussed in greater detail below under “ Liquidity and Capital Resources ”. 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. 12 Table of Contents Participations Agreements Related to D-J Basin Assets On August 21, 2024, the Company, through PRH, entered into a five-year Participation Agreement with a large private equity-backed D-J Basin exploration and production company with extensive operational experience (“ Joint Development Party ”), whereby the Joint Development Party assigned to PRH a 30% interest in approximately 7,607 net acres of existing oil and gas leases and PRH assigned to the Joint Development Party a 70% interest in approximately 3,166 net acres of oil and gas leases, all located within the SW Pony Prospect in the D-J Basin in Weld County, Colorado. Additionally, to facilitate joint development of the SW Pony Prospect, the parties agreed to an Area of Mutual Interest covering approximately 16,900 gross acres wherein the parties have the opportunity to participate in subsequent leasehold acquisitions proportionate to their working interest under the Participation Agreement. Each party’s participation is based on their proportionate share of the total acquisition cost. The Company participated in six wells which were drilled and completed in 2024 (the Harlequin wells), and four wells which were drilled and completed in the fourth quarter of 2025 (three Mavericks wells and one Jaws well), all of which were within this Area of Mutual Interest. 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 has 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, with no election having been made to date. Merger Agreement On October 31, 2025 (the “ Closing ”), we entered into the Agreement and Plan of Merger with NP Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Company, COG Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Company, North Peak Oil & Gas, LLC, a Delaware limited liability company, Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company, and, solely for purposes of the specified provisions therein, North Peak Oil & Gas Holdings, LLC, a Delaware limited partnership. Pursuant to the Merger Agreement, (a) First Merger Sub merged with and into NPOG, with NPOG being the surviving entity and a wholly owned subsidiary of the Company, and (b) Second Merger Sub merged with and into COG, with COG being the surviving entity and a wholly owned subsidiary of the Company. Subject to the terms and conditions of the Merger Agreement, all of the issued and outstanding limited liability company interests of each of NPOG and COG were automatically converted into the right to receive an aggregate of 10,650,000 validly issued, fully paid and nonassessable shares of newly designated Series A Convertible Preferred Stock of the Company (the “ Merger Preferred Shares ”), par value $0.001 per share (the “ Series A Preferred Stock ”), which shares were issued to Century Oil and Gas Holdings, LLC, a Delaware limited liability company (“ Century ”) and North Peak. The Series A Preferred Stock automatically converted into shares of common stock of the Company, par value $0.001 per share (the “ Automatic Conversion ”), at a ratio of 0.5-to-1, effective February 27, 2026, following the expiration of the twenty calendar day period commencing on the distribution of an information statement to the Company’s shareholders in accordance with Rule 14c-2 of Regulation 14C promulgated under the Exchange Act (the “ Automatic Conversion Date ”). On the Automatic Conversion Date, the Merger Preferred Shares converted into an aggregate of 5,325,000 shares of Company common stock. Amended and Restated Credit Agreement On October 31, 2025, the Company entered into an Amended and Restated Credit Agreement (the “ A&R 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 ”). 13 Table of Contents 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, including for certain asset sales, elimination or reduction of hedge positions and title defects. The A&R Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its subsidiaries to, among other things, incur additional indebtedness, incur additional liens, enter into mergers and consolidations, make or declare dividends, make investments and loans, engage in transactions with affiliates. 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 are expected to be used to fund the Company’s participation in certain non-operated well operations and to pay other Company obligations. A total of $98 million is currently outstanding under the A&R Credit Agreement as of the date of this filing. PIPE Offering Concurrently with the Closing of the Mergers, certain investors (the “ PIPE Investors ”) subscribed for and purchased an aggregate of 6,363,637 shares of Series A Preferred Stock (the “ PIPE Preferred Shares ”), at a price per share equal to $5.50 per share (the “ Purchase Price ”) ($11.00 per share on a post -reverse stock split basis) , pursuant to their entry into Series A Convertible Preferred Stock Subscription Agreements in favor of the Company (the “ Subscription Agreements ”). On the Automatic Conversion Date, the PIPE Preferred Shares converted into 3,181,818 shares of Company common stock (the “ PIPE Conversion Shares ”). The PIPE Investors included (a) The SGK 2018 Revocable Trust, a family trust of which Dr. Simon Kukes, the then Executive Chairman of the Company is trustee and beneficiary ($15,409,977); (b) American Resources, Inc., an entity owned and controlled by J. Douglas Schick, the Chief Executive Officer, President and member of the Board ($250,003); (c) Clark R. Moore, the Executive Vice President, General Counsel and Secretary of the Company ($25,003); (d) John J. Scelfo Revocable Trust Dated October 8, 2003, a trust of which John J. Scelfo, a member of the Board, is trustee and beneficiary ($550,000); (e) Jody D. Crook, the Chief Commercial Officer of the Company ($25,003); (f) J PED, LLC, an entity affiliated with Juniper Capital Advisors, L.P. (“ Juniper ”) ($18,550,004); (g) Reagan T. Dukes, the then Chief Executive Officer of the Acquired Companies, who was appointed Chief Operating Officer of the Company at the Closing of the Mergers ($52,503) and (h) Robert J. Long, the then Chief Financial Officer of the Acquired Companies, who was appointed Chief Financial Officer, Treasurer and Principal Accounting/Financial Officer of the Company at the Closing of the Mergers ($52,503). The PIPE Financing closed concurrently with the Mergers and the $35,000,004 of net proceeds raised by the Company pursuant to the PIPE Financing was used to pay off certain liabilities of the Acquired Companies in connection with the Mergers and certain expenses of the PIPE Financing and Mergers. Second Amended and Restated Designation of Series A Convertible Preferred Stock In preparation for the Closing of the Mergers, the Board of Directors approved the Second Amended and Restated Certificate of Designations establishing the rights, preferences, and limitations of the Company’s Series A Convertible Preferred Stock on October 29, 2025, which was filed with the Texas Secretary of State on October 31, 2025. A total of 17,013,637 shares of Series A Preferred Stock were designated. Except as required by law or the designation, Series A Preferred Stockholders had no voting rights, except the right to elect one director (the “ Series A Director ”) until the Automatic Conversion Date, with Josh Schmidt serving as such director. Holders of Series A Preferred Stock were entitled to certain protective provisions, requiring approval by a majority in interest of outstanding shares for actions such as amending governing documents, changing board composition, issuing new securities, major acquisitions or disposals, indebtedness above $500,000, executive appointments, and other material corporate actions. The holders of Series A Preferred Stock were provided no dividend rights, and in the event of liquidation, dissolution, or winding-up, Series A holders were to receive distributions pari passu with common shareholders, as if their shares were converted to common stock. All of the 17,013,627 then outstanding shares of Series A Preferred Stock converted on the Automatic Conversion Date, into an aggregate of 8,506,818 shares of the Company common stock in a ratio of 0.5-for-1. 14 Table of Contents Additionally, on February 27, 2026, the Company, after approval of the Board of Directors and the stockholders pursuant to the Written Consent, filed a Second Amended and Restated Certificate of Formation of the Company, which among other things, terminated the designation of the Series A Preferred Stock. As such, as of the date of this Report, we have no Series A Preferred Stock outstanding or designated. Competition The oil and natural gas industry is highly competitive. We compete, and will continue to compete, with major and independent oil and natural gas companies for exploration and exploitation opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Many of our competitors have substantially greater financial resources, staffs, facilities and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs. Our ability to exploit, drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. Many of our competitors have a longer history of operations than we have, and many of them have also demonstrated the ability to operate through industry cycles. Risk Management We are exposed to certain risks relating to our ongoing business operations, including commodity price risk. In accordance with our company strategy and the covenants under the A&R Credit Agreement, derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil, natural gas and natural gas liquids production. We do not enter into derivative contracts for speculative trading purposes. While there are many different types of derivative instruments available, we have used costless collars, producer three-way collars, standalone put options, fixed-price swaps and basis swaps to attempt to manage price risk. Costless collar and three-way producer collar agreements are combinations of put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All collar agreements provide for payments between the counterparties if the settlement price under the agreement exceeds the ceiling or if the settlement price under the agreement is below the floor. Standalone put options are floors that are purchased for a cost and provide that counterparties make payments to us if the settlement price is below the established floor. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement. The basis swaps agreements effectively lock in a price differential between regional prices where the product is sold and the relevant pricing index under which oil or natural gas production is hedged. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We will continue to evaluate the benefit of employing derivatives in the future. Our hedge strategies and objectives may change as our operational profile changes see “ Item 8 Financial Statements and Supplementary Data ” – “ Note 10 - Derivatives )”for additional information. Competitive Strengths We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths: Legacy Conventional Focus . Legacy conventional oil fields that have seen large-scale vertical development. Vertical production confirms moveable hydrocarbons ideal for horizontal development that may have been technologically or economically limited or missed. Technical Engineering & Operations Expertise . Lateral landing decisions incorporate log analysis, fracture-geometry modeling and an understanding of local porosity and saturation distributions. Our team are creative problem solvers with expertise in wellbore mechanics, completion design, production enhancement, artificial lift design, water handling, facilities optimization, and production down-time reduction. 15 Table of Contents Low-Cost Development . From shallow conventional reservoirs to deeper sand and shale plays across the Rockies, we have stacked pay that offers attractive returns and efficient full-scale development opportunities across our portfolio. Management . We have assembled a management team at our Company with extensive experience in the fields of business development, petroleum engineering, geology, field development and production, operations, planning and corporate finance. Our management team is headed by J. Douglas Schick, who has served as our President since 2018 and as our Chief Executive Officer since January 2025 and also serves as a member of our Board of Directors, and has over 25 years of experience in the oil and gas industry, having co-founded American Resources, Inc., and formerly serving in executive, management and operational planning, strategy and finance roles at Highland Oil and Gas, Mariner Energy, Inc., The Houston Exploration Co., ConocoPhillips and Shell Oil Company. Additionally, our Chief Commercial Officer, Jody D. Crook, has over 25 years of experience in the oil and gas industry, having co-founded oil and gas consulting and operational firms Tenet Advisory Group LLC and Bronze Four Resources, LLC, and formerly serving in various leadership roles and positions of increasing responsibility at Jones Energy, Ltd., Southwestern Energy, and Enron Corp. In addition, Reagan Tuck (R.T.) Dukes, who was appointed as our Chief Operating Officer effective October 31, 2025, has nearly 20 years of experience in the oil and gas industry, with extensive experience in oil and gas investing, finance, research, and consulting, having formerly served as the chief financial officer and as the chief executive officer of Century Natural Resources, LLC, as a research director and director of North American supply at Wood Mckenzie Limited, and as a manager at KED Interests, LLC. Furthermore, Robert “Bobby” Long, who was appointed as our Chief Financial Officer effective October 31, 2025, has nearly 25 years of financial experience in management, corporate finance, and principal investing in the energy industry, having formerly served as the chief financial officer of Century Natural Resources, LLC, as the chief financial officer of Navigation Petroleum, as an executive director of CIBC Capital Markets, as a partner in Rivington Holdings, LLC, as an associate, and then vice president, of BNP Paribas, Global Energy Group, and as an analyst at JP Morgan Chase & Co., Energy Finance. Also, our Executive Vice President and General Counsel, Clark R. Moore, has 20 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp. All members of the management and operations teams have also successfully helped develop and build similar exploration and production companies with like kind asset profiles and technical operations in multiple oil and gas producing basins in the United States. We believe that our management team is highly qualified to identify, acquire and exploit energy resources in the U.S. Our Board of Directors also brings extensive oil and gas industry experience, headed by our Chairman, Josh Schmidt, who brings over 15 years of experience in the energy industry, currently serving as a partner, chief operating officer and member of the investment committee of Juniper, and previously having worked at Citigroup Energy in Houston, Texas, as a natural gas and electricity trader. Our Board also includes Edward Geiser, the founder and Executive Managing Partner of Juniper and head of its investment committee, who previously served as a managing director at Och-Ziff, and in the investment banking groups of both Merrill Lynch and Morgan Stanley. In addition, our Board includes John Howie, who has over 40 years of experience in oil and gas engineering, management, and finance, formerly serving as president of Tellurian Production Company, founder and manager of Impact Natural Resources and Parallel Resource Partners, as Head of E&P Global Capital at Goldman, Sachs and Company, as vice president of EnCap Investments, L.L.C., and at various other E&P companies, including Range Resources Corporation, Apache Corporation, and Amoco Corporation. Our Board also includes Martyn Willsher, currently chief executive officer of Unified Petroleum LLC, who formerly served as chief executive officer, senior vice president, and chief financial officer of Amplify Energy Corp., and held various management roles at Memorial Production Partners GP, LLC and Constellation Energy, and served in various business development and financial analysis roles at JM Huber Corp., FTI Consulting and PricewaterhouseCoopers LLP. Our Board also includes Kristel Franklin, who brings deep expertise spanning integrated upstream and midstream operations with over 20 years of experience in the oil and gas industry, currently serving as chief operating officer of PureWest Energy, and previously leading Moontower Resources, LLC to a successful exit for Oaktree Capital, and serving in various roles of increasing responsibility at Three-Rivers Operating Company III and Jones Energy, and at Exxon Mobil Corporation as a Senior Drilling Engineer. Significant acreage positions and drilling potential . As of December 31, 2025, we have accumulated interests in a total of 99,561 net acres in our core D-J Basin Asset operating area, 201,886 net acres in our core Powder River Basin Asset operating area, and 14,105 net acres in our core Permian Basin Asset operating area, all of which we believe represent significant upside potential. The majority of our interests are in or near areas of considerable activity by both major and independent operators, although such activity may not be indicative of our future operations. Based on our current acreage position, we believe our D-J Basin Asset could contain up to 450 potential gross well locations of varying lateral lengths. We believe our Powder River Basin Asset could contain up to 455 potential gross well locations of varying lateral lengths. We also believe our Permian Basin Asset could contain up to 155 potential gross 1.0 mile lateral locations. Combined our asset base could contain over 1,000 gross locations of varying lateral lengths providing years of potential inventory. Not all of these potential well locations in our D-J Basin Asset, Powder River Basin and Permian Basin Asset are included in our reserve report due to SEC guidelines related to development timing. 16 Table of Contents Marketing We generally sell a significant portion of our oil and gas production to a relatively small number of customers, and during the year ended December 31, 2025, sales to two customers comprised 26% and 22%, respectively, of the Company’s total oil and gas revenues. No other customer accounted for more than 10% of our revenue during these periods. The Company is not dependent upon any one purchaser and believes that, if its primary customers are unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices. For properties in which we are a non-operator, we are highly dependent on the success of our third-party operators and the decisions made in connection with their operations. Our third-party operators sell our oil, natural gas, and NGLs to purchasers, collect the cash, and distribute the cash to us. In the year ended December 31, 2025, one individual operator accounted for more than 10% of our total production revenues, representing approximately 30% of our total production sales for the year. Oil . Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers. Crude oil prices realized from production sales are indexed to published posted refinery prices, and to published crude indexes with adjustments on a contract basis. Transportation costs related to moving crude oil are also deducted from the price received for crude oil. Natural Gas . Our natural gas is predominately sold under short-term natural gas purchase agreements, with one gas purchase agreement. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees for processing, location or transportation differentials. Following the Mergers, the Acquired Companies continue to maintain agreements with various midstream providers for the gathering, processing and marketing of their oil and gas production, including long-term arrangements with Roaring Fork Midstream, LLC (“ RFM ”) covering a majority of production in Laramie County, Wyoming, which extend beyond 2030 and do not include minimum volume commitments. Although Juniper Capital Advisors, L.P. previously controlled RFM and retains a minority equity interest, the agreements are on arm’s-length terms. Additional crude volumes are gathered or sold through three separate, non-affiliated companies at prevailing market prices subject to customary marketing and transportation deductions. Oil and Gas Properties We believe that our D-J Basin, PRB, and Permian Basin Assets represent among the most economic oil and natural gas plays in the U.S. We plan to opportunistically seek additional acreage proximate to our currently held core acreage located in the Wattenberg and Wattenberg Extension areas of Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, and elsewhere in the D-J Basin, the PRB, and the Northwest Shelf of the Permian Basin in Chaves and Roosevelt Counties, New Mexico. Our D-J Basin strategy is to participate in projects we deem highly economic on an operated or non-operated basis as our acreage position does not always allow for us to serve as operator in the D-J Basin. Our strategy in the PRB and the Permian Basin is to be the operator and/or a significant working interest owner, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan. 17 Table of Contents Our Core Areas D-J Basin Asset We hold our combined D-J Basin Asset through our wholly-owned subsidiaries PRH Holdings LLC (PRH), and North Peak Oil & Gas, LLC (NPOG) an additional wholly-owned subsidiary acquired through the Mergers. Operations are conducted through our wholly-owned operating subsidiaries, including Red Hawk Oil & Gas, LLC (“Red Hawk”), Longs Peak Resources, LLC (LPR), and North Silo Resources, LLC (NSR). Our D-J Basin Asset was assembled through our legacy operations and expanded significantly through the Mergers which, as discussed above, closed on October 31, 2025. Prior to the Mergers, we had grown our legacy D-J Basin position to approximately 15,853 net acres in Weld and Morgan Counties, Colorado, and approximately 4,823 net acres in Laramie County, Wyoming. Through the Merger, we acquired additional substantial D-J Basin interests held by the Acquired Companies, with 72,022 net acres being located in Laramie County, Wyoming, and an additional 6,863 net acres located in Weld County, Colorado, making Wyoming the location of a majority of our combined D-J Basin net acreage. As of December 31, 2025, our combined D-J Basin Asset consisted of 99,561 net leasehold acres, of which approximately 22,716 net acres are located in Colorado and approximately 76,845 net acres are located in Wyoming. More than 88% of our net D-J Basin acreage is located on private lands. As of December 31, 2025, approximately 70% of our net D-J Basin acres are held by production (“HBP”), and we hold an average working interest of approximately 92% across our operated net D-J Basin acreage (inclusive of our net royalty acres). Our D-J Basin Asset acreage is located in the areas shown in the map below. 18 Table of Contents We serve as operator of 74 gross (66.9 net) wells in our D-J Basin Asset, and we participate as a non-operated working interest owner in an additional 110 gross (12.5 net) wells, for a combined total of 184 gross (79.4 net) wells as of December 31, 2025. The D-J Basin is one of the most prolific oil and natural gas producing basins in the United States, extending from northern Colorado into southeastern Wyoming and western Nebraska. Our operated D-J Basin program is focused primarily on horizontal wells targeting the Codell sandstone formation, a Lower Cretaceous siliceous sandstone that has demonstrated strong well productivity across our operated acreage in southeastern Wyoming. Our non-operated working interest participations are concentrated in horizontal wells targeting the Niobrara formation, which consists of multiple productive carbonate benches commonly referred to as the “A,” “B,” and “C” benches, and which is the primary development target for many of the leading operators active in the D-J Basin. The Wattenberg and Wattenberg Extension areas of northern Colorado and the Wyoming D-J Basin Extension have experienced a sustained and significant increase in horizontal drilling activity since 2018, driven by continued advances in completion design, including extended lateral lengths, increased proppant loading, additional frac stages, and improved stage spacing, that have materially improved well productivity and capital efficiency across both formations. Wyoming is recognized as one of the most oil and gas operator-friendly regulatory environments in the United States. Our D-J Basin operations in Wyoming are subject to oversight by the Wyoming Oil and Gas Conservation Commission (“WOGCC”), and our Colorado D-J Basin operations are subject to oversight by the Colorado Energy & Carbon Management Commission (“ECMC”). We actively pursue operatorship across our acreage position where our leasehold ownership and surface configuration permit us to do so. Our D-J Basin acreage is concentrated in areas proximate to leading public and private operators with active and growing Niobrara and Codell development programs. Our non-operated working interest participations benefit from the continued Niobrara-focused horizontal development programs of notable operators including Chevron Corporation (which acquired Noble Energy in October 2020 and PDC Energy in August 2023), SM Energy Company (which merged with Civitas Resources, Inc. in January 2026, with SM Energy as the surviving entity), EOG Resources, Inc., Occidental Petroleum Corporation, Bison Oil & Gas IV, and Peoria Resources, LLC (a U.S. subsidiary of Japan Petroleum Exploration Co., Ltd. (“JAPEX”), which completed the acquisition of Verdad Resources LLC’s operated D-J Basin portfolio in February 2026), among others. Continued development by these offset and partner operators provides ongoing geological delineation and production data that further support our understanding of the economic potential of our acreage across both our operated and non-operated positions. Our primary operated D-J Basin development program targets the Codell sandstone formation with horizontal wells on our Wyoming acreage, where we serve as operator and control the pace of development. In our non-operated D-J Basin acreage, our strategy is to participate in Niobrara-focused horizontal development projects operated by leading public and private E&P companies that we deem highly economic based on well-level returns and capital efficiency. We are actively enhancing our D-J Basin land position through organic leasing, pooling, acreage swaps, bolt-on acquisitions, and the pursuit of additional operatorship opportunities similar to the recently completed Mergers. Post closing of the Mergers, we implemented a maintenance capital program focused on optimization projects on our producing wells, including well cleanouts, compression optimization, and artificial lift conversions, which we expect to meaningfully lower our lease operating expenses on a per-unit basis. We believe our combined D-J Basin Asset provides significant near-term development opportunities, with hundreds of potential drilling locations across both the Codell and Niobrara formations that are immediately adjacent to our existing producing wells. Powder River Basin Asset We hold our Powder River Basin Asset (our “PRB Asset”) through Century Oil & Gas Sub-Holdings, LLC, our wholly-owned subsidiary acquired through the Mergers, with operations conducted through Century Oil & Gas, LLC, Navigation Powder River, LLC, and Pine Haven Resources, LLC. Our PRB Asset was acquired in its entirety through the Mergers and represents a large-scale, multi-horizon resource opportunity in northeastern Wyoming. Our PRB Asset interests are primarily located in Johnson, Campbell, Converse, Weston, and Niobrara Counties in northeastern Wyoming. As of December 31, 2025, our PRB Asset consisted of 201,886 net leasehold acres. More than 89% of our net PRB acreage is located on federal lands administered by the Bureau of Land Management (“BLM”). As of December 31, 2025, approximately 53,222 of our net PRB acres are held by production, with the remainder held primarily by production payment (suspense) or on primary term. We hold an average working interest of approximately 76% on our operated net PRB acreage (including our net royalty acres). Our PRB Asset acreage is located in the areas shown on the map below. 19 Table of Contents We serve as operator of 140 gross (134.1 net) wells in our PRB Asset, and we participate as a non-operated working interest owner in an additional 16 gross (1.4 net) wells, for a combined total of 156 gross (135.4 net) wells as of December 31, 2025. The Powder River Basin is one of the most significant sedimentary basins in the Rocky Mountain region, characterized by a thick Cretaceous-age stratigraphic column with numerous stacked pay zones that provide extensive development optionality. Our PRB Asset targets a broad range of productive formations spanning both the Upper and Lower Cretaceous sections. Upper Cretaceous targets include the Teapot, Parkman, Sussex, and Shannon, while Lower Cretaceous and transitional targets include the Niobrara, Turner, Frontier, Mowry, and Muddy formations. We believe that this extensive stacked pay column, spanning thousands of feet, provides significant future development optionality for the Company across a broad range of commodity price environments and capital allocation strategies. Within our PRB acreage position, we have identified significant multi-formation development potential supported by active offset operator drilling activity across multiple horizons proximate to our acreage. Of particular note are the Parkman, Sussex, Niobrara, Turner, and Mowry formations, each of which has been subject to meaningful offset operator activity in areas adjacent to our acreage, providing ongoing geological and production data that in our opinion further supports the economic potential of these horizons across our position. We believe the breadth of active development across these stacked formations, combined with our concentrated acreage footprint in Johnson, Campbell, Weston, and Niobrara Counties, provides us with a compelling multi-formation development inventory and the flexibility to allocate capital to the highest-return opportunities as the basin continues to mature. 20 Table of Contents Given that a substantial majority of our PRB acreage is located on federal lands, our PRB operations are subject to regulatory oversight by both the BLM and the WOGCC. We work closely with these agencies with respect to permitting, right-of-way acquisition, development planning, and compliance obligations for our PRB operations. Wyoming’s demonstrated commitment to a stable and predictable regulatory environment for oil and gas development, including permitting timelines and operational flexibility on federal lands, makes our PRB position particularly well-suited for long-term capital allocation. Historical development activity on our PRB acreage has been focused primarily in the Central area of our position. More recently, both the North and West portions of our PRB acreage have seen a meaningful increase in offset operator activity, particularly in the Niobrara, Turner, Parkman, Sussex, and Mowry formations, which we believe will continue to delineate productivity and further support the economics of future development on our acreage. Notable operators active in the vicinity of our PRB acreage include Anschutz Exploration Corporation, Continental Resources, Inc., Devon Energy Corporation, EOG Resources, Occidental Petroleum Corporation, and various other large private operators, among others. We believe our large and concentrated PRB acreage position provides us with the potential for years of development optionality and the ability to allocate capital efficiently as commodity markets and offset operator activity continue to evolve. We evaluate future PRB development opportunities on an ongoing basis, with a focus on projects that generate strong risk-adjusted returns. Permian Basin Asset We hold our Permian Basin Asset through our wholly-owned subsidiary, PEDCO, with operations conducted through PEDCO’s wholly-owned operating subsidiary, Ridgeway Arizona Oil Corp. (RAZO). Our Permian Basin Asset was assembled through three acquisitions completed between 2018 and 2019. In the first acquisition, we acquired 100% of the assets of Hunter Oil Company, with an effective date of September 1, 2018, which created our core Permian position. In 2019, we acquired additional assets in two bolt-on acquisitions from private operators, and in November 2023 we divested approximately 8,035 gross leasehold acres and related wells in the non-core Milnesand and Sawyer Fields of our Permian Basin Asset to a private operator in order to reduce our asset retirement obligations and plugging and abandoning liabilities with respect to these non-core assets, thereby eliminating approximately $3.2 million in plugging and abandonment liabilities and freeing up our resources to allow us to better focus on development of our other assets. Our current Permian Basin Asset interests are all located in Chaves and Roosevelt Counties, New Mexico, where we currently operate 35 gross (33.5 net) wells, of which 28 wells are active producers, and two are active salt water disposal (“SWD”) wells. As of December 31, 2025, our Permian Basin Asset acreage is located where indicated in the below map of the State of New Mexico and more specifically in the areas shaded in yellow in the subsequent sectional map. 21 Table of Contents State of New Mexico 22 Table of Contents In September 2023, the Company and Evolution Petroleum Corporation (“Evolution”) entered into a Participation Agreement for the joint development of the Chaveroo oilfield in Chaves and Roosevelt Counties, New Mexico. The agreement covers twelve Development Blocks encompassing approximately 16,000 gross leasehold acres, within which the parties may jointly drill up to nine horizontal San Andres wells per block on a 50/50 working interest basis, with the Company serving as operator. Evolution's entry into each successive Development Block is optional, at a cost of approximately $450 per net acre, and either party may independently develop any block the other elects to skip. The agreement continues in effect for so long as the parties proceed with development, and new leases acquired by the Company within certain identified tracts within two years of signing are included as existing leases. To date,Evolution has acquired working interests in five Development Blocks: a 50% interest in approximately 813 net acres in the first and second Development Blocks for $366,000 in September 2023; a 50% interest in approximately 811 net acres in the third, fourth, and fifth Development Blocks for $365,000 in June 2024; and a 50% interest in approximately 640 net acres in the eighth Development Block for $288,000 in September 2025. In addition, in December 2023, the Company’s operating company, RAZO, entered into a Stipulated Final Order (“SFO”) with the Director of the Oil and Gas Conservation Division of New Mexico (the “OCD”) pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset 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. RAZO has been timely paying each reimbursement invoice received from the OCD in accordance with the SFO and is in full compliance with the SFO. The SFO superseded all previous Agreed Compliance Orders, as amended, entered into by and between RAZO and the OCD. 23 Table of Contents We believe that the Company’s approximately 14,550 net acres within the Chaveroo and Chaveroo NE Fields offer a unique opportunity to drill infill horizontal wells. The Chaveroo NE Field is an extension of the Chaveroo Field that was not originally developed vertically. Our current Permian Basin Asset interests are all located in Chaves and Roosevelt Counties, New Mexico, where we currently operate 35 gross (33.5 net) wells, of which 28 wells are active producers, and two are active SWDs. Production, Sales Price and Production Costs We have listed below the total production volumes and total revenue, net to the Company, for the years ended December 31, 2025, 2024, and 2023: 2025 2024 2023 Total Revenues $ 45,751,000 $ 39,553,000 $ 30,784,000 Oil: Total Production (Bbls) 672,924 492,396 382,794 Average sales price (per Bbl) $ 59.78 $ 73.50 $ 72.95 Natural Gas: Total Production (Mcf) 770,919 608,382 479,533 Average sales price (per Mcf) $ 3.45 $ 2.00 $ 3.00 NGL: Total Production (Bbls) 108,657 78,003 58,170 Average sales price (per Bbl) $ 26.30 $ 27.48 $ 24.43 Oil Equivalents: Total Production (Boe) (1) 910,068 671,796 520,886 Average Daily Production (Boe/d) 2,494 1,835 1,427 Average Production Costs (per Boe) (2) $ 11.62 $ 10.36 $ 8.98 _________________________ (1) Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil. (2) Excludes workover costs, marketing, ad valorem, severance taxes and ARO Settlements. As of December 31, 2025, the Wattenberg Field and the D-J Wyoming Field in our D-J Basin Asset, and as of December 31, 2024 the Wattenberg Field in our D-J Basin, and as of December 31, 2023, the Chaveroo Field in our Permian Basin Asset and the Wattenberg Field in our D-J Basin Asset are the fields that each comprise 15% or more of our total proved reserves. The applicable production volumes from these fields for the years ended December 31, 2025, 2024, and 2023, are represented in the table below in total barrels (Bbls): 2025* 2024 2023 Oil (Bbls): Chaveroo (Permian Asset Base) - - 157,413 Wattenberg (D-J Asset Base) 251,402 199,518 220,788 D-J Wyoming (D-J Asset Base) 187,005 - - Natural Gas (Mcf): Chaveroo (Permian Asset Base) - - 66,270 Wattenberg (D-J Asset Base) 599,845 445,650 354,570 D-J Wyoming (D-J Asset Base) 137,880 - - NGL (Bbls): Chaveroo (Permian Asset Base) - - - Wattenberg (D-J Asset Base) 83,856 59,842 52,013 D-J Wyoming (D-J Asset Base) 22,805 - - Total Production (Boe)(1): Chaveroo (Permian Asset Base) - - 168,458 Wattenberg (D-J Asset Base) 435,103 333,635 331,896 D-J Wyoming (D-J Asset Base) 232,790 - - (1) Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil. 24 Table of Contents The following table summarizes our gross and net developed and undeveloped leasehold acreage at December 31, 2025: Total Developed (1) Undeveloped (2) Gross Net Gross Net Gross Net D-J Basin 272,581 99,561 222,477 70,244 50,104 29,317 Powder River Basin 280,731 201,886 132,962 61,233 147,769 140,653 Permian Basin 26,240 14,105 21,760 13,785 4,980 320 Total 580,052 315,552 377,199 145,262 202,853 170,290 (1) Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production. (2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves. We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Total Net Undeveloped Acreage Expiration In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as follows: (i) in the D-J Basin Asset, 16,138 net acres are set to expire during 2026 (net to our direct ownership interest only), with 2,110 and 678 net acres set to expire for the years ending December 31, 2027 and 2028 respectively, and 8,081 net acres thereafter; (ii) in the Permian Basin Asset only 200 net acres are set to expire for the year ending December 31, 2026; and (iii) in the Powder River Basin Asset, 4,822 net acres are set to expire during 2026, with 34,999 and 15,828 net acres set to expire for the years ending December 31, 2027 and 2028, respectively (net to our direct ownership interest only), with all of the remaining acreage currently held by production. Well Summary The following table presents our ownership in productive crude oil and natural gas wells at December 31, 2025. This summary includes crude oil wells in which we have a working interest: Gross Net Crude oil 344.0 225.4 Natural gas - - Total* 344.0 225.4 * Total percentage of gross operated wells is 66.3%. Drilling Activity We drilled wells or participated in the drilling of wells as indicated in the table below: 2025 2024 2023 Gross Net Gross Net Gross Net Development Productive 36 8.5 27 5.1 8 0.4 Dry - - - - - - Exploratory Productive - - - - - - Dry - - - - - - 25 Table of Contents The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2025, which are not included in the above table: Drilling In Progress Drilled But Uncompleted Gross Net Gross Net Development wells - - 11 1.2 Exploratory wells - - - - Total - - 11 1.2 Oil and Natural Gas Reserves Reserve Information. For estimates of the Company’s net proved producing reserves of crude oil and natural gas, as well as discussion of the Company’s proved and probable undeveloped reserves, see “ Part II ” - “ Item 8 Financial Statements and Supplementary Data ” – “Supplemental Oil and Gas Disclosures (Unaudited) ”. At December 31, 2025, the Company’s total estimated proved reserves were 32.1 million Boe, of which 27.3 million Bbls were crude oil and NGL reserves, and 28.8 million Mcf were natural gas reserves. Internal Controls. Arvind Krishna, our Director of Development and Reservoir Engineering (a non-executive position), is the technical person primarily responsible for our internal reserves estimation process (which is based upon the best available production, engineering and geologic data) and has in excess of five years as a reserves estimator and provides oversight of the annual audit of our year end reserves by our independent third party engineers. He has a Master of Science degree in Petroleum Engineering from The University of Texas at Austin and an MBA from Rice University. The preparation of our reserve estimates is in accordance with our prescribed procedures that include verification of input data into reserve forecasting and economic software, as well as management review. Our reserve analysis includes, but is not limited to, the following: · Research of operators near our lease acreage. Review operating and technological techniques, as well as reserve projections of such wells. · The review of internal reserve estimates by well and by area by a qualified petroleum engineer. A variance by well to the previous year-end reserve report is used as a tool in this process. · SEC-compliant internal policies to determine and report proved reserves. · The discussion of any material reserve variances among management to ensure the best estimate of remaining reserves. Qualifications of Third-Party Engineers. The technical person primarily responsible for the audit of our reserves estimates at Cawley, Gillespie & Associates, Inc. is W. Todd Brooker, who meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Cawley, Gillespie & Associates, Inc. is an independent firm and does not own an interest in our properties and is not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. A copy of the report issued by Cawley, Gillespie & Associates, Inc. is incorporated by reference as Exhibit 99.1 to this Report. For more information regarding our oil and gas reserves, please refer to “ Item 8 Financial Statements and Supplementary Data ” – “Supplemental Oil and Gas Disclosures (Unaudited) ”. 26 Table of Contents Current Year Events Merger Agreement On October 31, 2025, the Company closed the transactions contemplated by an Agreement and Plan of Merger dated October 31, 2025, by and among the Company; NP Merger Sub, LLC and COG Merger Sub, LLC, each a wholly owned subsidiary of the Company; NPOG; COG; and, solely for specified purposes therein, North Peak Oil & Gas Holdings, LLC. Pursuant to the Merger Agreement, (i) NP Merger Sub, LLC merged with and into NPOG, with NPOG surviving as a wholly owned subsidiary of the Company, and (ii) COG Merger Sub, LLC merged with and into COG, with COG surviving as a wholly owned subsidiary of the Company. Highlights of the Company following the Mergers: · The Mergers position the Company as a premier publicly traded Rockies-focused operator with an expanded footprint of approximately 320,000 net acres across the D-J Basin and the PRB. The transaction significantly increases the Company’s oil-weighted production and enhances its scale in these core operating areas. · The Company generates strong cash flow supported by its relatively high oil production mix and competitive cost structure. Its substantial acreage position in the D-J Basin and Powder River Basin, which includes multiple productive formations, provides more than a decade of identified drilling inventory based on current development plans. · The Company maintains a low-cost operating profile characterized by disciplined general and administrative expenses and a conservative capital structure, which management expects to preserve going forward. · The Company believes that it is positioned for organic production growth, with 32 wells (with varying working interests) recently completed in the fourth quarter of 2025 and early first quarter of 2026. These wells are expected to drive near-term production increases. In addition, the Company intends to pursue strategic consolidation opportunities within its core areas of focus, targeting acquisitions that are expected to be accretive and generate operational synergies, while maintaining balance sheet strength. Drilling and Completion, Leasing, and Mineral Lease Acquisition Activities For the year ended December 31, 2025, the Company incurred $239.2 million of capital additions of which $204.6 million were related to the Mergers (noted above) and $34.0 million of capital costs were primarily related to the Company’s completion operations with respect to four operated wells, drilled and completed with a third-party, as well as five lift conversions in the Permian Basin. The Company also participated in the drilling and completion of 23 non-operated wells in the D-J Basin for which production had begun in late 2025, with the Company working interest holdings in these wells ranging from 8% to 44%. Additionally, the Company acquired approximately 100 net mineral acres and 310 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions at total acquisition and due diligence costs of $194,000 and $420,000, respectively. Amended and Restated A&R Credit Agreement On October 31, 2025, the Company entered into an Amended and Restated Credit Agreement, which amended and restated its prior senior secured revolving credit agreement dated September 11, 2024, with Citibank, N.A., as administrative agent, and the lenders party thereto. The A&R Credit Agreement matures on October 31, 2029 and provides for an initial borrowing base and elected commitments of $120 million, with a maximum revolving commitment of $250 million. The borrowing base is subject to scheduled semiannual redeterminations beginning December 1, 2025, as well as unscheduled redeterminations and other adjustments, and is determined by the lenders in their discretion. Borrowings are subject to customary conditions, including compliance with financial covenants. The A&R Credit Agreement includes customary representations and warranties 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. In connection with the closing of the Mergers, the Company borrowed $87 million under the A&R Credit Agreement, with additional borrowings of $6 million on January 8, 2026 and $5 million on February 5, 2026. 27 Table of Contents Issuance and Automatic Conversion of Series A Convertible Preferred Stock As part of the Mergers (noted above), the Company issued Series A Convertible Preferred Stock in two transactions. First, 10,650,000 shares of Series A Convertible Preferred Stock were issued to Century Oil and Gas Holdings, LLC and North Peak in exchange for their interests in the Acquired Companies. Second, 6,363,637 shares of Series A Convertible Preferred Stock were sold to the PIPE Investors at $5.50 per share ($ 11.00 per share on a post-reverse stock split basis) , raising $35.0 million in net proceeds, which were used to pay for certain liabilities and transaction expenses in the Mergers (noted above). All shares of Series A Convertible Preferred Stock were convertible into common stock at a 0.5-to-1 ratio. A total of 17,013,637 shares of Series A Convertible Preferred Stock were issued and outstanding as of December 31, 2025. On February 27, 2026, all shares of Series A Convertible Preferred Stock automatically converted into 8,506,818 shares common stock of the Company. Shareholder Agreement At the closing of the Mergers, the Company entered into a Shareholder Agreement with Century and North Peak (together, the “ Juniper Shareholder ”), and, for certain limited provisions, Dr. Simon G. Kukes, the then Executive Chairman of the Company and The SGK 2018 Revocable Trust (a trust which Dr. Kukes serves as trustee and beneficiary of). The agreement granted the Juniper Shareholder board nomination rights from the closing of the Mergers until the Automatic Conversion Date, including the ability to designate one board nominee and one non-voting observer. The agreement also provides that, following the Automatic Conversion Date, the Board will consist of six directors, with Juniper’s nominees determined by its ownership percentage of shares of the Company’s common stock on the Automatic Conversion Date. Specifically, the right of the Juniper Shareholder to nominate Juniper Directors pursuant to the Shareholder Agreement will depend on its, together with its affiliates’, ownership of 3,181,818 shares of Company common stock issued to the Juniper Shareholder and its affiliates on February 27, 2026, on the applicable date of determination, as measured relative to a total of 13,300,815 shares of common stock issued and outstanding on February 27, 2026 (“ Juniper Beneficial Ownership ”), as follows: if Juniper Beneficial Ownership is 50% or more, the Juniper Shareholder may nominate three Juniper Directors, including one which must be an independent director; if Juniper Beneficial Ownership is between 30% and 49.9%, the Juniper Shareholder may nominate two Juniper Directors; if Juniper Beneficial Ownership is between 10% and 29.9%, the Juniper Shareholder may nominate one Juniper Director; and if Juniper Beneficial Ownership is less than 10%, the Juniper Shareholder loses the right to nominate any Juniper Directors. The Juniper Shareholder also retains the right to remove or replace its directors, subject to Board approval and suitability requirements under SEC and NYSE standards. At least one Juniper Shareholder director will serve on each Board committee (except the audit committee), and will chair the Compensation and Governance Committees, subject to limited exceptions. The Shareholder Agreement also grants the shareholders registration rights, requiring the Company to use commercially reasonable efforts to file a registration statement covering the resale of the shares of common stock issuable upon conversion of the Series A Preferred Stock within 45 days of the Automatic Conversion Date, using Form S-3 or Form S-1 if necessary. Shareholders may request underwritten offerings of at least $10 million, subject to customary agreements and underwriter approval, with limits on frequency and “grace periods” for delays. Piggyback registration rights allow participation in offerings by the Company or other holders, subject to underwriter and priority rules. The Company will pay related expenses and indemnify shareholders against certain Securities Act of 1933, as amended liabilities. The Shareholder Agreement became effective at the Closing and will terminate according to its terms. The “Shareholder Agreement” is discussed in greater detail below under “Item 10. Directors, Executive Officers and Corporate Governance—Shareholder Agreement”. On February 27, 2026 (the Automatic Conversion Date), the Board, with the recommendation of the Nominating and Corporate Governance Committee of the Board, and at the request of the Juniper Shareholder, pursuant to the terms of the Shareholder Agreement (discussed above), increased the number of members of the Board from five (5) to six (6), and appointed Mr. Edward Geiser as a member of the Board and as Chairperson of the Nominating and Corporate Governance Committee of the Board of Directors, to serve until his successor has been duly elected and qualified, or until his earlier death, resignation or removal. 28 Table of Contents Also effective on February 27, 2026, director Josh Schmidt was appointed as Chairman of the Board of the Company. Reverse Stock Split Effective March 13, 2026, the Company effected the 1-for-20 Reverse Stock Split discussed above under “Reverse Stock Split” and as a result of the Reverse Stock Split, every twenty (20) shares of issued and outstanding common stock were automatically combined into one (1) share of common stock. No fractional shares were issued in connection with the Reverse Stock Split. Instead, each holder of common stock received a cash payment in lieu thereof at a price equal to the fraction of one share to which the stockholder would otherwise be entitled multiplied by the closing price per share of common stock on the NYSE American on the trading day immediately prior to the effective time of the Reverse Stock Split. All share amounts, per-share data, earnings (loss) per share, and weighted-average shares outstanding presented in the accompanying consolidated financial statements and related notes have been retroactively adjusted to reflect the Reverse Stock Split for all periods presented. Regulation of the Oil and Gas Industry Crude oil and natural gas production operations are subject to various types of regulation, including regulation by federal and state agencies. Federal legislation affecting the oil and gas industry is under constant review for amendment or expansion. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry. Such rules and regulations, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictions on flaring, require surety bonds for various exploration and production operations and regulate the calculation and disbursement of royalty payments (for federal and state leases), production taxes and ad valorem taxes. A portion of our oil and gas leases are granted by the federal government and administered by the BLM. Operations conducted by the Company on federal oil and gas leases must comply with numerous additional statutory and regulatory restrictions and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations. In addition, the U.S. Department of the Interior (through its agencies, including the BLM and the Office of Natural Resources Revenue) has certain authority over our calculation and payment of royalties, bonuses, fines, penalties, assessments and other revenues related to our federal and tribal oil and gas leases. In addition, the Inflation Reduction Act of 2022 (the “ IRA ”) requires that all leases granted and administered by the BLM and entered into on or after August 16, 2022, include a royalty rate of 16.67% in respect of the associated oil and gas production. In addition, 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. 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 National Environmental Policy Act (“ NEPA ”) 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 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. Operations conducted by the Company are also subject to the NEPA which requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that pertains to the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Certain of the Company’s exploration, development and production activities include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the procedural requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in environmental assessments or Environmental Impact Statements, we could incur added costs, which may be substantial. For example, 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 (“ APDs ”) with respect to the certain of the Company’s BLM leases, citing erroneous data that overstated the amount of available groundwater in the Project’s Environmental Impact Statement. This ruling had the effect of halting federal APD approvals within the Project area 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 and could result in the cancellation of these leases. However, in January 2025, President Trump issued an executive order requiring the Council on Environmental Quality (“ CEQ ”) to provide guidance on implementing NEPA and to propose rescinding and replacing CEQ’s NEPA regulations with implementing regulations at the agency level. The executive order also instructs federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations and our ability to obtain governmental permits. 29 Table of Contents BLM leases contain relatively standardized terms requiring compliance with detailed regulations. 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. From time to time, the U.S. Department of the Interior has also considered limiting or pausing new oil and natural gas leases on federal lands. Any limitation or ban on permitting for oil and gas exploration and production activities on federal lands could have a material and adverse effect on our operations, financial condition and results of operations. The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938, as amended (the “ NGA ”), and the Natural Gas Policy Act of 1978. These statutes are administered by the Federal Energy Regulatory Commission (“ FERC ”). Effective January 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all “ first sales ” of natural gas, which includes all sales by the Company of its own production. All other sales of natural gas, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of our sales of natural gas may currently be made at unregulated market prices, subject to applicable contract provisions. Jurisdictional sales, however, may be subject in the future to greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales. Conversely, sales of crude oil and NGLs by the Company are made at unregulated market prices. Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and other federal, state and local regulatory commissions, agencies, councils and courts. We cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the oil and gas industry historically has been very heavily regulated; therefore, there is no assurance that the approach currently being followed by such legislative bodies and regulatory commissions, agencies, councils and courts will remain unchanged. At the state level, our operations in Colorado are regulated by the ECMC (formerly the Colorado Oil & Gas Conservation Commission (“ COGCC ”)), our operations in Wyoming are regulated by the Wyoming Oil and Gas Conservation Commission (“ WOGCC ”), and our New Mexico operations are regulated by the Conservation Division of the New Mexico Energy, Minerals, and Natural Resources Department (regulates oil and gas operations), New Mexico Environment Department (administers environmental protection laws), and the New Mexico State Land Office (oversees surface and mineral acres and development). The Oil Conservation Division of the New Mexico Energy, Minerals, Natural Resources Department (“ EMNRD ”), and New Mexico State Land Office require the posting of financial assurance for owners and operators on privately owned or state land within New Mexico in order to provide for abandonment restoration and remediation of wells, and for the drilling of salt water disposal wells. Environmental Regulation Generally We are subject to various federal, state and local laws and regulations covering the discharge or release of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations affect our operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations and related activities (e.g., carbon capture and storage). Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, criminal prosecution, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements. 30 Table of Contents In addition, we have acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under our control. Under environmental laws and regulations, we could be required to remove or remediate wastes disposed of or released by prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such third-party sites. In addition, we could be responsible under environmental laws and regulations for oil and gas properties in which we previously owned or currently own an interest but were or are not currently the operator. Moreover, we are currently subject to certain reporting requirements promulgated by U.S. Environmental Protection Agency’s (the “ EPA ”) regarding, among other things, GHG emissions and other fugitive emissions. And, as discussed further below, we are also subject to federal, state and local laws and regulations regarding hydraulic fracturing and other aspects of our operations. Compliance with environmental laws and regulations increases our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition, results of operations or capital expenditures (for environmental control facilities or otherwise). In addition, it is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to our total exploration and development expenditure program in order to comply with such laws and regulations. However, we are unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding the environment and (ii) the ultimate cost of compliance or the ultimate effect on our operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations. The direct and indirect cost of such laws and regulations (if enacted) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Accordingly, future implementation and enforcement of certain environmental laws or regulations are uncertain at this time. Climate Change Regulations Local, state, federal and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. Congress has, from time to time, proposed legislation for imposing restrictions on, or requiring fees or carbon taxes in respect of, GHG emissions. Further, the IRA imposes a methane emissions charge on certain oil and gas facilities, including petroleum and natural gas production facilities that exceed certain emissions thresholds. The charge will be levied annually based on emissions reported under the EPA’s GHG reporting program. In November 2024, the EPA finalized a regulation to implement the IRA’s Waste Emissions Charge, which became effective on January 1, 2025. The fee imposed under the Methane Emissions Reduction Program for 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026. In January 2025, industry associations challenged the Waste Emissions Charge rule in the D.C. Circuit Court of Appeals. Also in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. In late February 2025, the newly seated Congress successfully passed a joint resolution (H.J. Res. 35) using the Congressional Review Act (CRA) to officially disapprove of the EPA’s November 2024 rule implementing the methane fee and President Trump signed this resolution into law in March 2025, effectively nullifying the previously adopted Methane Emissions Reduction Program. In addition, based on the timing of the rule's finalization and statements from congressional Republicans, the waste emissions charge rule is potentially vulnerable to repeal by Congress under the Congressional Review Act, and the IRA may also be subject to amendment or repeal through Congressional budget reconciliation. Consequently, future implementation and enforcement of these rules remains uncertain at this time. The EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act. Further, the EPA, in May 2016, issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds (“ VOC ”) from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector, and, in November 2022, the EPA issued a supplemental proposal to expand its November 2021 proposed rule, including proposed regulation of additional sources of methane and VOC emissions, such as abandoned and unplugged wells. The EPA issued the final new source performance standards and emissions guidelines for new and existing oil and gas facilities in December 2023, and although in effect, the final rule is subject to ongoing litigation. Furthermore, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. 31 Table of Contents In 2019, Colorado enacted Senate Bill 19-181 (“ SB 19-181 ”), which requires, among other things, that the Air Quality Control Commission (“ AQCC ”) adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC has undertaken a multi-year rulemaking process to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. Between December 2019 and December 2020, the AQCC completed several rulemakings as a result of SB 19-181, adopting significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements, increased LDAR frequencies for facilities in certain proximity to occupied areas, and emission control requirements for certain large natural gas fired engines. The AQCC conducted an additional rulemaking in December 2021 related to SB 19-181, which is discussed in further detail below. State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment’s (“ CDPHE ”) Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In 2020, the ECMC relied in part on a previously-performed human health risk assessment in adopting new siting requirements. The new requirements prohibit the siting of locations within 2,000 feet of a school facility or child-care center. A similar 2,000-foot setback requirement applies to residential and high occupancy building units, but there are “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. The ECMC also generally prohibited the venting or flaring of natural gas during drilling, completion, and production operations. In addition, on August 30, 2022, environmental groups filed a petition for rulemaking with the ECMC, petitioning the ECMC to adopt new rules to evaluate and address the cumulative air impacts of oil and gas development in Colorado. The petition proposes to address the cumulative air impacts of oil and gas development by effectively prohibiting any oil and gas project located in an area where the air quality exceeds, or may exceed, applicable air quality standards. In effect, the petition for rulemaking calls for a blanket prohibition on oil and gas development in much of Colorado. The COGCC (now ECMC) denied the petition; however, the COGCC (now the ECMC) initiated a cumulative impacts stakeholder process to determine how best to address cumulative impacts going forward, which may include additional regulations. Since 2022, the ECMC has introduced regulatory measures impacting the oil and gas industry, including: (i) in August 2024, the ECMC proposed regulations aimed at assessing and mitigating the cumulative effects of oil and gas operations, particularly in communities disproportionately impacted by environmental burdens, which rules are now in place as of December 15, 2024; and (ii) in April 2022, the ECMC implemented new financial assurance rules mandating that oil and gas operators provide adequate funds to cover well plugging and site reclamation. AQCC rulemakings are intended to further Colorado’s legislative directive to reduce carbon dioxide, methane and other greenhouse gases (“ GHGs ”) emissions to attain climate action goals. AQCC is expected to undertake several rulemaking efforts to further reduce emissions in the next several years. For example, in October 2023, the AQCC adopted the Greenhouse Gas Emissions and Energy Management for Manufacturing Phase 2 rule, which requires 18 of Colorado’s highest emitting manufacturers in the industrial sector (which includes energy use in the oil and gas industry) to collectively reduce their GHG levels by 20% by 2030, as compared to 2015 levels. In 2021, the State of New Mexico Energy, Minerals and Natural Resources Department (“ ENMRD ”) enacted rule changes aimed at mitigating volumes of flared and vented natural gas. Commencing April 1, 2022, operators are required to reduce the annual volume of vented and flared natural gas in order to capture no less than ninety-eight percent of the natural gas produced from all wells by December 31, 2026 (New Mexico Administrative Code Section 19.15.27.9). This rule change is accompanied by additional reporting requirements for all flared and vented gas. We expect to meet or exceed the required gas capture requirements in accordance with this rule change. 32 Table of Contents In addition, the New Mexico state legislature is considering a bill that would increase fines and fees on oil and gas operators and codify New Mexico’s 98% methane capture rule, which the New Mexico Energy, Minerals and Natural Resources Department (“ NMOCD ”) enacted in 2021. Under the methane capture rule, oil and gas operators are required to capture 98% of their produced natural gas by December 31, 2026, and routine venting and flaring is prohibited. In addition, the NMOCD adopted a rule in August 2022 that requires oil and natural gas producers in counties that are at risk of non-attainment of federal ozone standards to, among other things, check emission rates and have those calculations certified by a qualified engineer, perform enhanced checks for leaks, repair those leaks within 15 days of discovery, and maintain records to demonstrate continuous compliance. At the international level, the U.S., in December 2015, participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement, which was adopted at the conference and went into effect in November 2016, calls for nations to undertake efforts with respect to global temperatures and set GHG emissions reduction goals every 5 years beginning in 2020. In February 2021, the Biden Administration announced reentry of the U.S. into the Paris Agreement along with a new “ nationally determined contribution ” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. Pursuant to its obligations as a signatory to the Paris Agreement, the United States set a target to reduce its GHG emissions by 50-52% by the year 2030 as compared with 2005 levels. In addition, in 2021, the Biden Administration publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “ all feasible reductions ” in the energy sector. Since its formal launch at the United Nations Framework Convention on Climate Change 26th Conference of the Parties (“ COP26 ”), over 150 countries have joined the pledge. COP26 concluded with the finalization of the Glasgow Climate Pact (the “ Glasgow Pact ”), which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. At the 27th Conference of the Parties, the United States agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. In December 2023 at the 28th Conference of the Parties, nearly 200 countries entered into an agreement that calls for actions towards achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to contribute to the transition away from fossil fuels, reduce methane emissions and increase renewable energy capacity, among other things, in order to achieve global net zero emissions by 2050. Most recently, at the 29th Conference of the Parties (“ COP29 ”), delegates approved rules to operationalize international carbon markets under Article 6 of the Paris Agreement, including a new Paris Agreement Crediting Mechanism to trade UN-approved carbon credits. Additionally, participants at COP29 representing 159 countries met to review progress toward the goals of the Global Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement. On January 20th, 2025, the Trump Administration announced its intention to withdraw from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The full impact of these actions remains unclear at this time. However, various state and local governments in the U.S. have publicly committed to furthering the goals of the Paris Agreement and many of these initiatives are expected to continue. We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations, treaties or policies regarding climate change and GHG emissions (including any laws and regulations that may be enacted in the U.S.), but the direct and indirect costs of such investigations, laws, regulations, treaties or policies (if enacted, issued or applied) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures. Regulation of Hydraulic Fracturing and Other Operations Hydraulic fracturing technology, which has been used by the oil and gas industry for more than 60 years and continues to evolve, enables us to produce crude oil and natural gas that otherwise would not be recovered. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA’s wastewater pretreatment standards prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to environmental requirements may result in increased costs. In addition to the above-described federal regulations, some state and local governments have imposed, or have considered imposing, various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells, testing of nearby water wells, restrictions on access to, and usage of, water, disclosure of the chemical additives used in hydraulic fracturing operations, restrictions on the type of chemical additives that may be used in hydraulic fracturing operations and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologically or seismically sensitive areas and other protected areas. Such federal, state and local permitting and disclosure requirements, operating restrictions, conditions or prohibitions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. 33 Table of Contents Compliance with laws and regulations relating to hydraulic fracturing and other aspects of our operations increases our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition, results of operations or capital expenditures. In addition, it is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts that are material in relation to our total exploration and development expenditure program in order to comply with such laws and regulations. However, we are unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the U.S. or other aspects of our operations; and (ii) the ultimate cost of compliance or the ultimate effect on our operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations. The direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures. Other State Laws At the state level, Colorado, where we conduct significant operations, is among the states that has adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations. Moreover, states could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Also, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time-to-time advanced various options for ballot initiatives that, if approved, would allow revisions to the state constitution in a manner that would make such exploration and production activities in the state more difficult in the future. However, during the November 2016 voting process, one proposed amendment placed on the Colorado state ballot making it relatively more difficult to place an initiative on the state ballot was passed by the voters. As a result, there are more stringent procedures now in place for placing an initiative on a state ballot. In addition to state laws, local land use restrictions may restrict drilling or the hydraulic fracturing process and cities may adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. For example, on November 6, 2018, registered voters in the State of Colorado cast their ballots and rejected Proposition 112 (“ Prop. 112 ”), with 55% of ballots cast against the measure. Prop. 112 would have created a rigid 2,500-foot setback from oil and gas facilities to the nearest occupied structure and other “vulnerable areas,” which included parks, ball fields, open space, streams, lakes and intermittent streams. It would have dramatically increased the amount of surface area off-limits to new energy development by 26 times and put 94% of private land in the top five oil and gas producing counties in the State of Colorado off-limits to new development. It is possible that future ballot initiatives will be proposed that could limit the areas of the state in which drilling would be permitted to occur or otherwise impose increased regulations on our industry. Passed in Colorado in 2019, SB 19-181 gives local governmental authorities increased authority to regulate oil and gas development. The authors of the legislation were clear that SB 19-181 was not intended to allow an outright ban on oil and gas development. However, anti-industry activists in Longmont, Colorado, have argued in court that SB 19-181 permits a local governmental authority to impose such a ban. We primarily operate in the rural areas of the Wattenberg Field in Weld and Morgan Counties, jurisdictions in which there has historically been significant support for the oil and gas industry. In addition, on September 28, 2020, the COGCC (now the ECMC) voted in favor of a preliminary approval establishing a new 2,000-foot setback rule from buildings for drilling and fracturing operations statewide, increasing the previous 500-foot setback rule, which rule became effective January 1, 2021, and could likewise make it more difficult for us to undertake oil and gas development activities in Colorado, although given the distance of most of our current leases from buildings in Colorado, these setback rules have not yet had a significant impact on our operations, but may impact future development if we seek develop acreage within such setback boundaries. 34 Table of Contents Further, on May 10, 2022, the Colorado Legislature adopted SB 22-198, the “Orphaned Oil and Gas Well Enterprise” bill, which requires each oil and gas operator in Colorado to pay a mitigation fee to the “enterprise” for each well that has been spud but not yet plugged and abandoned. The ECMC submitted a notice of rulemaking on May 18, 2022, to implement SB 22-198 by amending the ECMC’s annual registration fee rules to require that an operator’s annual registration fee be paid to the enterprise as a “mitigation fee.” In addition, the newly established “Enterprise Board” now has the authority to adjust the dollar amount of the mitigation fee. The amendments became effective on June 30, 2022, and may increase the registration fees required for current and future oil and gas wells in Colorado. We anticipate that the ECMC, the Conservation Division of the New Mexico Energy, Minerals, Natural Resources Department, the New Mexico State Land Office, the New Mexico Environment Department and other federal, state and local authorities will continue to adopt new rules and regulations moving forward which will likely affect our oil and gas operations and could make it more costly for our operations or limit our activities. We routinely monitor our operations and new rules and regulations which may affect our operations, to ensure that we maintain compliance. In New Mexico, the Company, through its New Mexico operating subsidiary RAZO, has entered into a Stipulated Final Order with the OCD pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset 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. RAZO has been timely paying each reimbursement invoice received from the OCD in accordance with the SFO and is in full compliance with the SFO. The SFO superseded all previous Agreed Compliance Orders, as amended, entered into by and between RAZO and the OCD. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells. In the event that local or state restrictions or prohibitions are adopted in areas where we conduct operations, that impose more stringent limitations on the production and development of oil and natural gas, including, among other things, the development of increased setback distances, we and similarly situated oil and natural exploration and production operators in the state may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we and similarly situated operates are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells. Moreover, because most of our operations are conducted in three particular areas, the D-J Basin in Colorado, the PRB in Wyoming, and the Permian Basin in New Mexico, legal restrictions imposed in those areas will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted in the D-J Basin in Colorado, and/or the PRB and/or the D-J Basin in Wyoming, and/or the Permian Basin in New Mexico that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Endangered Species and Migratory Birds Considerations The federal Endangered Species Act (“ ESA ”), and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. Similar protections are offered to migrating birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist, including the lesser prairie chicken which is now considered endangered as of November 2022, and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of one or more agreements entered into by the U.S. Fish and Wildlife Service, the agency is required to make a determination on listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The identification or designation of the lesser prairie chicken as endangered, and previously unprotected species as threatened or endangered, in areas where underlying property operations are conducted, could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. Currently, all net acres in our Permian Basin Asset have been designated as critical or suitable habitat for the lesser prairie chicken, which could adversely impact the pace of our development and the value of these leases. 35 Table of Contents Other We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“ OSHA ”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016. Republican control of the House, Senate and White House could lead to decreased regulatory oversight and decreased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes. Private Lawsuits Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities. Should private litigation be initiated against us, it could result in injunctions halting our development and production operations, thereby reducing our cashflow from operations, and incurrence of costs and expenses to defend any such litigation. Related Permits and Authorizations Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations. We are not able to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing, but the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our business, financial conditions and results of operations. See further discussion in “ Part I ” – “ Item 1A. Risk Factors .” Insurance Our oil and gas properties are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, implosions, fires and oil spills. These conditions can cause: · damage to or destruction of property, equipment and the environment; · personal injury or loss of life; and · suspension of operations. We maintain insurance coverage that we believe to be customary in the industry against these types of hazards. However, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations. 36 Table of Contents Human Capital Resources At March 27, 2026, we employed 25 people and also utilize the services of independent contractors to perform various field and other services. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. The development, attraction and retention of employees is a critical success factor for the Company. To support the advancement and education of our employees, we offer training and development programs to our employees, including training on compliance, general business, management, harassment prevention, leadership, and workplace safety-related topics to further their personal and professional development. We also require annual anti-harassment training of all employees and supervisors. We also offer our employees competitive pay and benefits. The Company’s compensation programs are designed to align the compensation of our employees with the Company’s performance and to provide the proper incentives to attract, retain and motivate employees to achieve superior results. The structure of our compensation programs balances incentive earnings for both short-term and long-term performance. Specifically: · We provide employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. · Annual increases and incentive compensation are based on merit, which is communicated to employees at the time of hiring and documented through our annual review procedures and upon internal transfer and/or promotion. · All employees are eligible for health insurance, paid and unpaid leaves, a retirement plan and life and disability/accident coverage. We also offer a variety of voluntary benefits that allow employees to select the options that meet their needs, including flexible spending accounts, flexible time-off, telemedicine, wellness resources, legal resources and identity protection plans, family leave, and adoption assistance, among others. Available Information The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Exchange Act. Such reports and other information filed by the Company with the SEC are available free of charge at https://www.pedevco.com/sec-filings when such reports are available on the SEC’s website. The Company periodically provides other information for investors on its corporate website, www.pedevco.com . This includes press releases and other information. The information contained on the websites referenced in this Annual Report is not incorporated by reference into this filing. Further, the Company’s references to website URLs are intended to be inactive textual references only. 37 Table of Contents