UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2025

For the transition period from ________________ to ____________

Commission file number: 001-35922

Registrant’s Telephone Number, Including Area Code: (713) 221-1768

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:  None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐   No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒   No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒   No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.  ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐   No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2025 (the last trading day of the registrant’s most recently completed second fiscal quarter), based upon the closing price of $13.09 on June 30, 2025, the last reported trading price prior to such date, was approximately $23,070,209. For purposes of calculating the aggregate market value of shares held by non-affiliates, we have assumed that all outstanding shares are held by non-affiliates, except for shares held by each of our executive officers, directors and 5% or greater stockholders. In the case of 5% or greater stockholders, we have not deemed such stockholders to be affiliates unless there are facts and circumstances which would indicate that such stockholders exercise any control over our company, or unless they hold 10% or more of our outstanding common stock. These assumptions should not be deemed to constitute an admission that all executive officers, directors and 5% or greater stockholders are, in fact, affiliates of our company, or that there are not other persons who may be deemed to be affiliates of our company.

On March 13, 2026, the Company effected a 20-for-1 reverse stock split of its common stock. The aggregate market value disclosed above reflects the closing price and shares outstanding as of June 30, 2025 and has not been adjusted to give retroactive effect to the reverse stock split.

As of March 27, 2026, 13,300,621 shares of the registrant’s common stock, $0.001 par value per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

Table of Contents

REVERSE STOCK SPLIT

On October 29, 2025, stockholders of PEDEVCO Corp. (the “Company”, “we” and “us”) who collectively held more than two-thirds of the combined voting power of the total issued and outstanding shares of Company common stock, executed a written consent in lieu of a special meeting of stockholders of the Company (the “Written Consent”), approving among other things, the grant of discretionary authority to the Company’s Board of Directors (the “Board”) to (A) approve an amendment to the Company’s Certificate of Formation, as amended, to effect a reverse stock split of our issued and outstanding shares of common stock, by a ratio of between one-for-ten to one-for-twenty, inclusive, with the exact ratio to be set at a whole number to be determined by our Board or a duly authorized committee thereof in its discretion, at any time after approval of the amendment and prior to October 30, 2026, and (B) determine whether to arrange for the disposition of fractional interests by stockholder entitled thereto, to pay in cash the fair value of fractions of a share of common stock as of the time when those entitled to receive such fractions are determined, or to entitle stockholder to receive from the Company’s transfer agent, in lieu of any fractional share, the number of shares of common stock rounded up to the next whole number (the “Stockholder Authority”).

The effectiveness of the Stockholder Authority was subject to the Company filing a definitive information statement on Schedule 14C, which was filed with the Securities and Exchange Commission (the “SEC” or the “Commission”) on February 2, 2026 (the “Information Statement”) and the mailing of such Information Statement to the Company’s stockholders describing among other things, the majority stockholders’ approval of the Stockholder Authority, which as described in greater detail in the Current Report on Form 8-K filed by the Company with the Commission on March 3, 2026, was mailed to the stockholders of the Company on February 6, 2026, in accordance with the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and as a result, the Stockholder Authority became effective on February 27, 2026, the 21st day following the mailing date of the Information Statement.

Following effectiveness of the Stockholder Authority, the Company’s Board approved an amendment to our Second Amended and Restated Certificate of Formation to effect a reverse stock split of our common stock at a ratio of 1-for-20, and to pay in cash the fair value of fractions of a share of common stock as of the time when those entitled to receive such fractions are determined (the “Reverse Stock Split”).

On March 10, 2026, we filed a Certificate of Amendment to our Second Amended and Restated Certificate of Formation (the “Certificate of Amendment”) with the Secretary of State of the State of Texas to effect the Reverse Stock Split.

Pursuant to the Certificate of Amendment, the Reverse Stock Split became effective on March 13, 2026 at 12:01 a.m. Eastern Time (the “Effective Time”). The shares of the Company’s common stock began trading on the NYSE American (“NYSE”) on a post-split basis on March 13, 2026, with a new CUSIP number of 70532Y402. No change was made to the trading symbol for the Company’s shares of common stock, “PED” in connection with the Reverse Stock Split.

At the Effective Time, every twenty (20) shares of issued and outstanding common stock will be converted into one (1) share of issued and outstanding common stock. No fractional shares were issued in connection with the Reverse Stock Split, and stockholders who would have otherwise been entitled to receive a fractional share as a result of the Reverse Stock Split instead received cash in lieu of such fractional share, based upon the closing sale price of the common stock on the trading day immediately prior to the Effective Time as reported on the NYSE American.

In addition, the number of shares of common stock issuable upon exercise of our stock options and other equity awards (including shares reserved for issuance under the Company’s equity compensation plans) were proportionately adjusted by the applicable administrator, using the 1-for-20 ratio, and rounded down to the nearest whole share, effective as of the Effective Time, pursuant to the terms of the Company’s equity compensation plans. In addition, the exercise price for each outstanding stock option was increased in inverse proportion to the 1-for-20 split ratio such that, upon exercise, the aggregate exercise price payable by the optionee to the Company for the shares subject to the option will remain approximately the same as the aggregate exercise price prior to the Reverse Stock Split, subject to the terms of such securities.

The effects of the Reverse Stock Split have been retroactively affected throughout this Report unless otherwise stated.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Report” or “Annual Report”) includes forward-looking statements within the meaning of the federal securities laws, including The Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “projects,” “estimates,” “plans,” “may,” and similar expressions or future or conditional verbs such as “should”, “would”, and “could” are generally forward-looking in nature and not historical facts. Forward-looking statements which are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs and cash flows, prospects, plans and objectives of management are forward-looking statements.  These forward-looking statements were based on various factors and were derived utilizing numerous important assumptions and other important factors that could cause actual results to differ materially from those in the forward-looking statements. Forward-looking statements include the information concerning our future financial performance, business strategy, projected plans and objectives. These factors include, among others, the factors set forth below under the heading “Risk Factors.” Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Most of these factors are difficult to predict accurately and are generally beyond our control. We are under no obligation to publicly update any of the forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events, except as required by law. Readers are cautioned not to place undue reliance on these forward-looking statements. As used herein, the “Company,” “we,” “us,” “our” and words of similar meaning refer to PEDEVCO Corp., which was known as Blast Energy Services, Inc. until July 30, 2012, and its consolidated subsidiaries, unless otherwise stated.

Forward-looking statements may include statements about:

All forward-looking statements speak only at the date of the filing of this Annual Report. The reader should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. We do not undertake any obligation to update or revise publicly any forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

In this Annual Report on Form 10-K, we may rely on and refer to information regarding the oil and oil and gas industry in general from market research reports, analyst reports and other publicly available information. Although we believe that this information is reliable, we have not commissioned any of such information, we cannot guarantee the accuracy and completeness of this information, and we have not independently verified any of it.

Our fiscal year ends on December 31st. Interim results are presented on a quarterly basis for the quarters ended March 31st, June 30th, and September 30th, the first quarter, second quarter and third quarter, respectively, with the quarter ending December 31st being referenced herein as our fourth quarter. Fiscal 2025 means the year ended December 31, 2025, whereas fiscal 2024 means the year ended December 31, 2024.

Certain abbreviations and oil and gas industry terms used throughout this Annual Report are described and defined in greater detail under “Glossary of Oil and Natural Gas Terms” below, and readers are encouraged to review that section.

Unless the context otherwise requires and for the purposes of this report only:

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas terms used in this Annual Report.

2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.

3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production.

AFE or Authorization for Expenditures. A document that lays out proposed expenses for a particular project and authorizes an individual or group to spend a certain amount of money for that project.

ARO. Asset retirement obligation, which is a legal obligation associated with the retirement of an oil or gas well, where the owner is responsible for removing equipment, plugging the well and/or cleaning up hazardous materials at some future date.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil or other liquid hydrocarbons.

Bcf. An abbreviation for billion cubic feet. Unit used to measure large quantities of gas, approximately equal to 1 trillion Btu.

Boe. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids, to six Mcf of natural gas.

Boepd. Barrels of oil equivalent per day.

Bopd. Barrels of oil per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Conventional resources. Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore.

Cushing/WTI. Means the price of West Texas Intermediate oil at the hub located in Cushing, Oklahoma.

Developed acreage. The number of acres that are allocated or assignable to productive wells.

Developed oil and natural gas reserves. Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

DSU. Is a drilling spacing unit, a designated, legally authorized, and mapped acreage area within which an operator is permitted to drill, ensuring proper well spacing for optimized resource extraction and regulatory compliance.

DUC. Is a drilled but uncompleted well.

Electric submersible pump or ESP. Is an artificial-lift method for lifting moderate to high volumes of fluids from wellbores.

Estimated ultimate recovery or EUR. Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.”

FERC. Federal Energy Regulatory Commission.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Frac or fracking. A short name for hydraulic fracturing, a method for extracting oil and natural gas.

Gross acres or gross wells. The total acres or wells in which a working interest is owned.

Held by production. An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property.

Henry Hub. A natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the NYMEX. The settlement prices at the Henry Hub are used as benchmarks for the entire North American natural gas market.

Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.

Hydraulic Fracturing. Means the forcing open of fissures in subterranean rocks by introducing liquid at high pressure, especially to extract oil or gas.

IP30. Means the production of a well for the first full calendar month of production.

Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane and pentane resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility.

LOE or Lease operating expenses. The costs of maintaining and operating property and equipment on a producing oil and gas lease.

MBbl or MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBbl/d. One thousand barrels of crude oil or other liquid hydrocarbons per day.

MBoe. Thousand barrels of oil equivalent.

MBoe/d. Thousand barrels of oil equivalent per day.

Mcf. One thousand cubic feet of natural gas.

Mcfgpd. Thousands of cubic feet of natural gas per day.

MMBtu. One million British thermal units.

MMBoe. Million barrels of oil equivalent.

MMcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.

Net revenue interest. The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well.

NGL. Natural gas liquids.

NYMEX. New York Mercantile Exchange.

Permeability. A reference to the ability of oil and/or natural gas to flow through a reservoir.

Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties.

Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. State regulations require generally plugging of abandoned wells.

Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.

Present value of future net revenues (“PV-10”). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.

Probable reserves. Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.

Producing well, production well or productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities that become part of the cost of oil, natural gas and NGL produced.

Properties. Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee, leasehold and related interests.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.

Proved undeveloped reserves or PUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Repeatability. The potential ability to drill multiple wells within a prospect or trend.

Reserves. Estimated remaining quantities of oil, natural gas and NGL and related substances anticipated to be economically producible by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil, natural gas and NGL or related substances to market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Salt Water Disposal Well or SWD. A salt water disposal (“SWD”) well is a disposal site for water produced as a result of the oil and gas extraction process.

Spud. Spudding is the process of beginning to drill a well in the oil and gas industry.

Standardized measure or standardized measure of discounted future net cash flows. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because standardized measure includes the effect of future income taxes on future net revenues. 

Transition Zone. The Transition Zone usually produces both oil and water at different ratios depending on the height above the Free Water Level (“FWL”). In normal conditions, wells that are drilled in the Transition Zone will produce at some water cut.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (a) low-permeability sandstone and shale formations and (b) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources.

Undeveloped acreage. 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 contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells.

Unproved and unevaluated properties. Refers to properties where no drilling or other actions have been undertaken that permit such property to be classified as proved.

USACE. United States Army Corps of Engineers.

Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water flows is pumped.

Volumetric reserve analysis. A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for the rock porosity, hydrocarbon saturation, formation volume factor and recovery factor.

Wellbore. The hole made by a well.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

WTI or West Texas Intermediate. A grade of crude oil used as a benchmark in oil pricing. This grade is described as light because of its relatively low density, and sweet because of its low sulfur content.

PART I

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.

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:

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.

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”).

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.

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.

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.

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. 

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.

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.

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.

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.

State of New Mexico

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.

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:

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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):

The following table summarizes our gross and net developed and undeveloped leasehold acreage at December 31, 2025:

(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:

* 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:

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:

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:

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)”.

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:

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.

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.

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.

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.

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.

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.

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.

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.

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.

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:

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.

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:

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.

ITEM 1A. RISK FACTORS.

An investment in our common stock involves a high degree of risk. You should carefully consider the risks described below as well as the other information in this filing before deciding to invest in our company. Any of the risk factors described below could significantly and adversely affect our business, prospects, financial condition and results of operations. Additional risks and uncertainties not currently known or that are currently considered to be immaterial may also materially and adversely affect our business, prospects, financial condition and results of operations. As a result, the trading price or value of our common stock could be materially adversely affected and you may lose all or part of your investment.

Summary Risk Factors

We face risks and uncertainties related to our business, many of which are beyond our control. In particular, risks associated with our business include:

Risks Related to the Oil, NGL and Natural Gas Industry; Our Business and Operations

Declines in oil and, to a lesser extent, NGL and natural gas prices, have in the past, and will continue in the future, to adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations or targets and financial commitments.

The price we receive for our oil and, to a lesser extent, natural gas and NGLs, heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, the nature and scale of our operations and future rate of growth. Oil, NGL and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 72% of our estimated proved reserves as of December 31, 2025 were oil, our financial results are more sensitive to movements in oil prices. The price of crude oil has experienced significant volatility over the last five years, with the price per barrel of West Texas Intermediate (“WTI”) crude, dropping below $48 per barrel in 2021 and surging to over $120 a barrel in early March 2022, following Russia’s invasion of the Ukraine, to the $90s in early 2026, and more recently increasing again to the mid-$90s per barrel following the initiation of the recent conflict in Iran . A prolonged period of low market prices for oil and natural gas, or further declines in the market prices for oil and natural gas, will likely result in capital expenditures being further curtailed and will adversely affect our business, financial condition and liquidity and our ability to meet obligations, targets or financial commitments and could ultimately lead to restructuring or filing for bankruptcy, which would have a material adverse effect on our stock price and indebtedness. Additionally, lower oil and natural gas prices have, and may in the future, cause, a decline in our stock price. The below table highlights the recent volatility in oil and gas prices by summarizing the high and low daily NYMEX WTI oil spot price and daily NYMEX natural gas Henry Hub spot price for the periods presented:

* Through March 16, 2026.

We have a limited operating history, have incurred net losses in the past and may incur net losses in the future.

We have a limited operating history and are engaged in the initial stages of exploration, development and exploitation of our leasehold acreage and will continue to be so until commencement of substantial production from our oil and natural gas properties, which will depend upon successful drilling results, additional and timely capital funding, and access to suitable infrastructure. Companies in their initial stages of development face substantial business risks and may suffer significant losses. We have generated substantial net losses in the past and may continue to incur net losses as we continue our drilling program. In considering an investment in our common stock, you should consider that there is only limited historical and financial operating information available upon which to base your evaluation of our performance. We have incurred net losses of $121,860,000 from the date of inception (February 9, 2011) through December 31, 2025. Additionally, we may be dependent on obtaining additional debt and/or equity financing to roll-out and scale our planned principal business operations. Management’s plans in regard to these matters consist principally of seeking additional debt and/or equity financing combined with expected cash flows from current oil and gas assets held and additional oil and gas assets that we may acquire. Our efforts may not be successful, and funds may not be available on favorable terms, if at all.

We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that one or more of our drilling programs is not completed or is delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this Annual Report and our subsequent periodic reports. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition. The uncertainty and risks described in this Annual Report may impede our ability to economically find, develop, exploit, and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by our operating activities in the future.

We may need additional capital to complete future acquisitions and conduct our operations and fund our business in and beyond 2026, and will need to raise additional capital to repay outstanding liabilities, and our ability to obtain the necessary funding is uncertain.

We may need additional capital to complete future acquisitions and conduct our operations and fund our business in and beyond 2026, and will need to raise additional capital to repay outstanding liabilities,  and may be required to raise additional funds through public or private debt or equity financing or other various means to repay outstanding liabilities, fund our operations and complete exploration and drilling operations in and beyond 2026 and acquire assets. In such a case, adequate funds may not be available when needed or may not be available on favorable terms. If we need to raise additional funds in the future by issuing equity securities, including sales of common stock under our December 2024 Sales Agreement entered into with Roth Capital Partners, LLC and A.G.P./Alliance Global Partners, pursuant to which we can sell up to $8 million in at-the-market offerings, dilution to existing stockholders will result, and such securities may have rights, preferences and privileges senior to those of our common stock, and/or through drawing debt under our A&R Credit Agreement. If funding is insufficient at any time in the future and we are unable to generate sufficient revenue from new business arrangements, to complete planned acquisitions or operations, our results of operations and the value of our securities could be adversely affected.

As of the date of this Report, we owe $98.0 million under our A&R Credit Agreement, which amounts are due and payable on October 31, 2029. Such funds may not be available when needed or may not be available on favorable terms.

Additionally, due to the nature of oil and gas interests, i.e., that rates of production generally decline over time as oil and gas reserves are depleted, if we are unable to drill additional wells and develop our reserves, either because we are unable to raise sufficient funding for such development activities, or otherwise, or in the event we are unable to acquire additional operating properties, we believe that our revenues will continue to decline over time. Furthermore, in the event we are unable to raise additional required funding in the future, we will not be able to participate in the drilling of additional wells, will not be able to complete other drilling and/or workover activities, and may not be able to make required payments on our outstanding liabilities.

If this were to happen, we may be forced to scale back our business plan, sell or liquidate assets to satisfy outstanding debts, all of which could result in the value of our outstanding securities declining in value.

We have been and may continue to be negatively impacted by inflation.

Recent increases in inflation have had an adverse effect on us. Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies, and geopolitical instability, including the recent armed conflict in Israel and the Gaza Strip, and the ongoing conflicts between the Ukraine and Russia and the United States and Iran, and the effect of tariffs. Increases in inflation, have in the past, and could in the future, impact our costs of labor, equipment and services and the margins we are able to realize on our wells, all of which could have an adverse impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the past, which in turn raises our cost of debt borrowing.

Economic uncertainty may affect our access to capital and/or increase the costs of such capital.

Global economic conditions continue to be volatile and uncertain due to, among other things, consumer confidence in future economic conditions, ongoing wars and conflicts, including the ongoing conflict between the United States and Iran, fears of recession and trade wars, the effect of tariffs, the price of energy, fluctuating interest rates, the availability and cost of consumer credit, the availability and timing of government stimulus programs, levels of unemployment, increased inflation, and tax rates. These conditions remain unpredictable and create uncertainties about our ability to raise capital in the future. In the event required capital becomes unavailable in the future, or more costly, it could have a material adverse effect on our business, results of operations, and financial condition.

We have entered into a Stipulated Final Order with the Director of the OCD which requires that the Company fund the plugging and abandonment of an aggregate of approximately 299 legacy vertical wells in our Permian Basin Asset, compliance with which may be costly and our failure to comply with the SFO may materially and adversely affect our business, results of operations and cash flows.

The Company has entered into an SFO with the OCD through RAZO, the Company’s New Mexico operating subsidiary, which requires, among other things, that the Company reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset (of which seven have been plugged to date) at a rate of $2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $30,000 per month by RAZO. 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. Such required payments and reimbursements may be significant, and may reduce our cash flows and funds available for our business plan and/or require us to raise additional funding in the future. Additionally, in the event the Company is unable to fully comply with the terms of the SFO, then the Company could be subject to significant civil penalties and sanctions, which would likely have a material adverse effect on our business, financial condition and results of operations, could require us to raise additional funding which may not be available on commercially reasonable terms, if at all, and may negatively affect our drilling plans in the future, and may cause the value of our securities to decline in value. 

All of our crude oil, natural gas and NGLs production is located in the Permian Basin, the Powder River Basin and the D-J Basin, making us vulnerable to risks associated with operating in only three geographic areas. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.

Our current operations are focused solely in the Permian Basin located in Chaves and Roosevelt Counties, New Mexico, and the D-J Basin of Weld and Morgan Counties, Colorado, with future operations extending into the Powder River Basin in Campbell and Laramie Counties, Wyoming, as a result of our October 2025 Mergers, with which means our current producing properties and new drilling opportunities are geographically concentrated in those three areas. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including:

For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Permian Basin, Powder River Basin, and D-J Basin may negatively affect our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Permian Basin, the Powder River Basin, and D-J Basin, the demand for, and cost of, drilling rigs, equipment, supplies, personnel and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations.

Drilling for and producing oil and natural gas are highly speculative and involve a high degree of risk, with many uncertainties that could adversely affect our business. We have not recorded significant proved reserves, and areas that we decide to drill may not yield oil or natural gas in commercial quantities or at all.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill, to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded, and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spudded, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well. Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following:

If we do not drill productive and profitable wells in the future, our business, financial condition and results of operations could be materially and adversely affected.

Our success is dependent on the prices of oil, NGLs and natural gas. Low oil or natural gas prices and the substantial volatility in these prices have adversely affected, and are expected to continue to adversely affect, our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial obligations.

The prices we receive for our oil, NGLs and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, NGLs and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. For example, the price of crude oil has experienced significant volatility over the last five years, with the price per barrel of West Texas Intermediate (“WTI”) crude, dropping below $48 per barrel in 2021, and surging to over $120 a barrel in early March 2022, following Russia’s invasion of the Ukraine, to the $60s in early 2026, to around $98 more recently following the initiation of the recent conflict in Iran.  Prices for natural gas and NGLs experienced declines of similar magnitude. An extended period of continued lower oil prices, or additional price declines, will have further adverse effects on us. The prices we receive for our production, and the levels of our production, will continue to depend on numerous factors, including the following:

Declines in oil, NGL or natural gas prices have not, and will not, only reduce our revenue, but have and will reduce the amount of oil, NGL and natural gas that we can produce economically. Should natural gas, NGL or oil prices decline from current levels and remain there for an extended period of time, we may choose to shut-in our operated wells, (similar to our shut-in of our operated wells in the Permian Basin and the D-J Basin in 2020 in response to the COVID-19 pandemic), delay some or all of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, and, as a result, we may have to make substantial downward adjustments to our estimated proved reserves, each of which would have a material adverse effect on our business, financial condition and results of operations.

We have in the past incurred impairments and future conditions might require us to incur additional impairments or make write-downs in our assets, which would adversely affect our balance sheet and results of operations.

We review our long-lived tangible and intangible assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. For example, for the year ended December 31, 2020, due to falling oil and gas prices, we incurred a $19.3 million impairment of our oil and gas properties with respect to our D-J Basin properties, and during the years ended December 31, 2024 and 2023, the Acquired Companies recorded impairment charges of $3.9 million and $21.1 million, respectively, with respect to their proved and unproved oil and natural gas properties in the  PRB for 2024 and both the PRB and D-J Basin for 2023. Aside from certain lease expirations, no significant impairment was incurred for the year ended December 31, 2025. We could be at risk for proved and unproved property impairments if we experience adverse market conditions for an extended period of time. The carrying values of our properties are sensitive to declines in oil, natural gas and NGL prices as well as increases in various development and operating costs and expenses. If oil, natural gas and NGL prices remain depressed for extended periods of time or decline materially from current levels, we may be required to record additional write-downs of the carrying value of our proved oil and natural gas properties. Further, we periodically evaluate our unproved oil and natural gas properties to determine the recoverability of our costs. Prior write-offs have adversely affected balance sheet assets and results of operations and any future significant write-offs would similarly adversely affect our balance sheet and results of operations.

Declining general economic, business or industry conditions have, and will continue to have, a material adverse effect on our results of operations, liquidity and financial condition, and are expected to continue having a material adverse effect for the foreseeable future.

Concerns over global economic conditions, the duration and effects of future pandemics, and the results thereof, energy costs, geopolitical issues (including, but not limited to the Israel/Gaza Strip conflict, the Ukraine/Russia conflict and the current Iran conflict), inflation, increasing interest rates and the availability and cost of credit have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, and declining business and consumer confidence, have precipitated an economic slowdown, which could expand to a recession or global depression. If the economic climate in the United States or abroad deteriorates, demand for petroleum products could diminish, which could further impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition to a greater extent that it has already.

Our business operations may be affected by worldwide economic, political and miliary events, including certain ongoing conflicts.

Worldwide economic, political and military events, including tax, trade and tariff policies of the United States and other countries involved in global energy markets, war, terrorist activity, events in the Middle East and initiatives by OPEC+, have contributed, and are likely to continue to contribute, to oil and natural gas price volatility. For example, recent events in Venezuela, the ongoing armed conflicts between Russia and Ukraine, and escalating tensions involving the United States, Israel and Iran, including direct military engagements and retaliatory actions, have led to heightened regional instability and increased global economic uncertainty. In particular, recent hostilities involving Iran have resulted in attacks on commercial shipping and energy infrastructure, as well as an effective disruption and, at times, near-total suspension of maritime traffic through the Strait of Hormuz, a critical chokepoint through which approximately 20% of the world’s oil supply transits.

The disruption of shipping lanes in and around the Persian Gulf, including congestion, rerouting and the anchoring of vessels outside the Strait of Hormuz, has caused significant delays in the transportation of crude oil, liquefied natural gas and refined products, and has contributed to increased freight, insurance and security costs, as well as volatility in global energy prices. In addition, damage to or disruption of key regional ports and infrastructure, including Iranian port facilities, and the risk of further military strikes or blockades, have exacerbated supply chain challenges and increased uncertainty regarding the availability and cost of energy commodities. The potential for broader regional conflict involving Iran, including possible prolonged closure or continued disruption of the Strait of Hormuz, as well as escalating hostilities involving the Houthi movement in Yemen, Hezbollah in Lebanon and other regional actors, has increased significantly.

Any continuation or escalation of these conflicts, including sustained disruptions to critical global shipping routes or energy infrastructure, could materially and adversely affect global supply and demand for oil and natural gas, increase commodity price volatility, disrupt our operations or those of our customers, suppliers or partners, and have a material adverse effect on our business, financial condition and results of operations.

Volatility in oil and gas prices makes it hard for us to plan and project our operations, capital expenditures, and financial performance.

Volatility in oil and natural gas prices, including for the reasons discussed in the risk factors above, significantly impairs our ability to accurately plan and project our operations, capital expenditures, and financial performance. These commodity prices are inherently unpredictable due to factors such as global supply and demand imbalances, geopolitical events, economic conditions, and regulatory changes, making it extremely difficult to forecast future price movements with any certainty. As a result, prolonged periods of low or highly volatile prices can lead to the reduction, deferral, or cancelation of exploration, development, and production activities, including but us or our operators. This uncertainty may force us to adjust our own capital spending plans, delay projects, revise budgets, and recalibrate internal projections and forecasts, which may result in reduced operational efficiency, impairments to proved reserves or other assets, and challenges in meeting financial targets or liquidity needs. For instance, sharp declines in prices can render certain development projects uneconomic, leading to lower-than-anticipated production volumes and cash flows, while sudden spikes may create inflationary pressures on costs without corresponding revenue gains in the near term. Ultimately, such price volatility contributes to greater unpredictability in our business planning, potentially materially and adversely affecting our results of operations, financial condition, and ability to execute our long-term strategy.

Our exploration, development and exploitation projects require substantial capital expenditures that may exceed cash on hand, cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash on hand, our operating cash flows and future potential borrowings may not be adequate to fund our future acquisitions or future capital expenditure requirements. The rate of our future growth may be dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.

Our cash flows from operations and access to capital are subject to a number of variables, including:

In addition, future events, such as terrorist attacks, wars and conflicts, threat of wars and conflicts, or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, pandemic diseases, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in additional exploration opportunities. Alternatively, a significant improvement in oil and natural gas prices or other factors could result in an increase in our capital expenditures, and we may be required to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or farm out of interests in our assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. Further, future debt financings may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Debt financing may involve covenants that restrict our business activities. If we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we choose to farm-out interests in our prospects, we may lose operating control over such prospects.

Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will receive, and significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

The accuracy of any estimates of proved reserves generally increases with the length of the production history. Due to the limited production history of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data is available, the estimated proved reserves will be re-determined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves.

Approximately 49% of our total proved reserves are classified as proved undeveloped and may ultimately prove to be less than estimated.

On December 31, 2025, approximately 49% of our total proved reserves of oil, natural gas and NGLs were classified as proved undeveloped. It will take substantial capital to drill our non-producing and undeveloped locations. Our estimate of proved reserves on December 31, 2025 assumes that we will need to spend significant development capital expenditures to develop these reserves. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

If actual reserves are lower than anticipated, the financial condition and results of operations of the Company could be adversely affected.

The Company’s ability to achieve anticipated production levels depends on the accuracy of its reserve estimates, which are inherently uncertain. Actual reserves may differ materially from estimates due to future development timing, development expenditures, operating costs, and reservoir performance as well as commodity price factors. If actual reserves are lower than anticipated, the financial condition and results of operations of the Company could be adversely affected.

Approximately 181,093 net acres in the PRB are located on federal lands as of December 31, 2025, which are subject to administrative permitting requirements, current and potential federal legislation, regulation and orders and pending litigation that may limit or restrict oil and natural gas operations on federal lands.

At December 31, 2025, approximately 181,093 net acres in the PRB were on federal lands administered by the Bureau of Land Management. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, the advancement of presidential administrative priorities and government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the availability of federal leases or the granting and renewal of permits or other licenses, approvals or certificates required to conduct our operations. Delays in making federal acreage available for leasing by oil and gas operators or obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. Under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our interests on federal lands.

In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. For example, in 2022, two environmental advocacy groups filed suit against the U.S. Department of Interior and the BLM challenging certain lease sales by the BLM beginning in December of 2017 (the “BLM Litigation”). On January 17, 2025, a three-judge panel of the Ninth Circuit Court of Appeals upheld vacatur of various leases sold by the BLM, on grounds that the BLM violated the NEPA (defined herein) and the Federal Land Planning and Management Act when selling certain leases. It remains unclear whether parties involved in the BLM Litigation will seek en banc review of the decision. While the Company is not named in the BLM Litigation (as defendants, intervenors or otherwise), certain of the leases owned by the Company in the PRB covering approximately 82,804 acres (as of December 31, 2025) have been “placed in suspense” pending a ruling by the Ninth Circuit Court of Appeals in the BLM Litigation. It is possible that the Ninth Circuit Court of Appeals ruling could result in the cancellation of these leases. In addition, as part of the BLM Litigation, on September 13, 2024, the U.S. District Court for the District of Columbia issued a ruling temporarily enjoining further applications for permits to drill with respect to certain of the Company’s BLM leases, citing erroneous data that overstated the amount of available groundwater in the Converse County Oil and Gas Project’s (the “Project’s”) Environmental Impact Statement. This ruling had the effect of halting federal APD approvals within the area of the Project until the court “determines the appropriate final remedy” to correct the deficiency being alleged in the case. It is possible that the BLM’s review and ultimate approval of our APDs could be impacted by this federal court ruling. If the January 17, 2025 Ninth Circuit Court of Appeals decision remains final, or if a final judgment on any similar future litigation results in the cancellation of leases or otherwise restricts production of our oil, natural gas or NGLs assets, our financial condition, results of operations and cash flows could be materially and adversely affected; however, we could also receive the return of up to $79 million of total lease bonuses previously paid in certain circumstances, which would have a positive effect on working capital.

Our hedging activities may prevent us from fully benefiting from increases in crude oil, natural gas and NGLs prices and may expose us to other risks, including counterparty risk, and our future production may not be sufficiently protected from any declines in commodity prices by our existing or future hedging arrangements.

We use financial derivative instruments (primarily financial fixed price swaps and collar contracts) to hedge the impact of fluctuations in commodity prices on our results of operations and cash flows. In connection with the entry into the A&R Credit Agreement, the Company was required to hedge at least 75% of its projected proved developed producing reserves (PDP) oil and gas production at the time of entry into the A&R Credit Agreement, for the first 24 months of the agreement, and 50% of its projected PDP of oil and gas production for months 25–36. Afterward, within 60 days after each fiscal quarter, the Company must show it has hedged at least 50% of expected oil and gas production for the next 18 months. The Company may hedge crude oil, natural gas, or natural gas liquids (on a barrel of oil equivalent basis) to meet these requirements, but may not hedge more than 75% of anticipated production (on a barrel of oil equivalent basis) for any month. As of the date of this report, the Company currently has approximately 75% of its crude oil production hedged through November 2027 and approximately 51% hedged from December 2027 through November 2028, and ~75% of its natural gas production hedged through November 2027 and approximately 50% hedged from December 2027 through November 2028, at various prices.

Our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. Our hedges may in the future result in losses and reduce the amount of revenue we would otherwise obtain upon the sale of our oil and natural gas production and may also decrease our margins and net revenues.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for the relevant period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

To the extent that we have engaged, or in the future engage, in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in commodity prices above the prices established by our hedging contracts. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

In addition, depending on the type of derivative arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil and gas prices. It cannot be assumed that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in commodity prices.

Increases in the differential between the ceiling value for oil and natural gas prices set forth in our commodity derivative contracts and commodity derivative collar contracts is anticipated to affect our business, financial condition and results of operations.

For more information regarding our current derivative instruments see “Item 8 Financial Statements and Supplementary Data” – “Note 10 – Derivatives”.

We may have accidents, equipment failures or mechanical problems while drilling or completing wells or in production activities, which could adversely affect our business.

While we are drilling and completing wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices.

Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. We maintain $2 million in general liability coverage and $10 million umbrella coverage that covers our and our subsidiaries’ business and operations. With respect to our other non-operated assets, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

Our strategy as an onshore resource player may result in operations concentrated in certain geographic areas and may increase our exposure to many of the risks described in this Annual Report.

Our current operations are concentrated in the states of New Mexico, Colorado, and Wyoming. This concentration may increase the potential impact of many of the risks described in this Annual Report. For example, we may have greater exposure to regulatory actions impacting New Mexico, Colorado, and/or Wyoming, adverse weather and natural disasters in New Mexico, Colorado, and/or Wyoming, competition for equipment, services and materials available in, and access to infrastructure and markets in, these states.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which will adversely affect our business, financial condition and results of operations.

The rate of production from our oil and natural gas properties will decline as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in (a) efficiently developing and exploiting our current reserves on properties owned by us or by other persons or entities and (b) economically finding or acquiring additional oil and natural gas producing properties. In the future, we may have difficulty acquiring new properties. During periods of low oil and/or natural gas prices, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our production, our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Our strategy includes acquisitions of oil and natural gas properties, and our failure to identify or complete future acquisitions successfully, or not produce projected revenues associated with the future acquisitions could reduce our earnings and hamper our growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Our financial position and results of operations may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our stockholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.

We may not be able to produce the projected revenues related to future acquisitions. There are many assumptions related to the projection of the revenues of future acquisitions including, but not limited to, drilling success, oil and natural gas prices, production decline curves and other data. If revenues from future acquisitions do not meet projections, this could adversely affect our business and financial condition.

We may purchase oil and natural gas properties with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our business, financial condition and results of operations could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.

We may incur losses or costs as a result of title deficiencies in the properties in which we invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the property, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.

Prior to the drilling of an oil and natural gas well, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our business, financial condition and results of operations.

Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas prices, assessment of risks, costs and drilling results. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report and the documents incorporated by reference herein, as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition and results of operations.

We currently license only a limited amount of seismic and other geological data and may have difficulty obtaining additional data at a reasonable cost, which could adversely affect our future results of operations.

We currently license only a limited amount of seismic and other geological data to assist us in exploration and development activities. We may obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost. In addition, even when properly interpreted, seismic data and visualization techniques are not conclusive in determining if hydrocarbons are present in economically producible amounts and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock.

The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition and results of operations.

Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase, and necessary equipment and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition and results of operations.

In addition, in the past, the demand for hydraulic fracturing services has exceeded the availability of fracturing equipment and crews across the industry and in our operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages may further amplify this equipment and crew shortage. Although we believe there is currently sufficient supply of hydraulic fracturing services, if demand for fracturing services increases or the supply of fracturing equipment and crews decreases, then higher costs could result and could adversely affect our business, financial condition and results of operations.

We have limited control over activities on properties we do not operate.

We are not the operator on all of our properties located in our D-J Basin and PRB Asset, and, as a result, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

The marketability of our production is dependent upon oil and natural gas gathering and transportation and storage facilities owned and operated by third parties, and the unavailability of satisfactory oil and natural gas transportation arrangements have had a material adverse effect on our revenue in the past and may again in the future.

The unavailability of satisfactory oil and natural gas transportation arrangements has in the past hindered our access to oil and natural gas markets and has delayed production from our wells. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of, oil and natural gas and the proximity of reserves to pipelines, terminal facilities and storage facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain these services on acceptable terms has in the past, and could in the future, materially harm our business. In the past we have, and in the future, we may be required to, shut-in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When this occurs, we are unable to realize revenue from those wells until the market for oil and gas increases and/or until production arrangements are made to deliver our production to market. Furthermore, we are obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases with respect to certain shut-in wells. We do not expect to purchase firm transportation capacity on third-party facilities. Therefore, we expect the transportation of our production to be generally interruptible in nature and lower in priority to those having firm transportation arrangements.

The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. The third parties' control when or if such facilities are restored after disruption, and what prices will be charged for products. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production has adversely affected our business, financial condition and results of operations.

The prices that we will receive for our oil and natural gas production sometimes may reflect a discount to the relevant benchmark prices, such as the New York Mercantile Exchange (“NYMEX”), that are used for calculating hedge positions. The difference between the benchmark price and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive has recently adversely affected, and is anticipated to continue to adversely affect our business, financial condition and results of operations. We do not have, and may not have in the future, any derivative contracts or hedging covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials.

Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flow from operations and adversely affect the exploration and development of our prospects and assets.

We derive and will derive in the future, substantially all of our revenues from the sale of our oil and natural gas to unaffiliated third-party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations.

Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.

The calculated present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net cash flows as included in our public filings is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under Generally Accepted Accounting Principles (“GAAP”) is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, and many of our competitors have more established presences in the United States than we have. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.

Our competitors may use superior technology and data resources that we may be unable to afford or that would require a costly investment by us in order to compete with them more effectively.

Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.

Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects.

Production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, as proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially.

Competition for hydraulic fracturing services and water disposal could impede our ability to develop our oil and gas plays.

The unavailability or high cost of high-pressure pumping services (or hydraulic fracturing services), chemicals, proppant, water and water disposal and related services and equipment could limit our ability to execute our exploration and development plans on a timely basis and within our budget. The U.S. oil and natural gas industry is experiencing a growing emphasis on the exploitation and development of shale natural gas and shale oil resource plays, which are dependent on hydraulic fracturing for economically successful development. Hydraulic fracturing in oil and gas plays requires high pressure pumping service crews. A shortage of service crews or proppant, chemical, water or water disposal options, especially if this shortage occurred in eastern New Mexico, eastern Colorado, or southern Wyoming, could materially and adversely affect our operations and the timeliness of executing our development plans within our budget.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. New Mexico, Colorado, and Wyoming, all have relatively arid climates and experience drought conditions from time to time and the U.S. Southwest is currently experiencing significant drought conditions which have reduced the flow of certain rivers and forced the reduction or reallocation of certain waterways and reservoirs. If we are unable to obtain water to use in our operations from local sources or dispose of or recycle water used in operations, or if the price of water or water disposal increases significantly, we may be unable to produce oil and natural gas economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Downturns and volatility in global economies and commodity and credit markets have, and in the future may, materially adversely affect our business, results of operations and financial condition.

Our results of operations have been, and in the future may be, materially adversely affected by the conditions of the global economies and the credit, commodities and stock markets. Among other things, in 2020 we were adversely impacted, and may be adversely impacted in the future, due to a global reduction in consumer demand for oil and gas. In addition, a decline in consumer confidence or changing patterns in the availability and use of disposable income by consumers can negatively affect the demand for oil and gas and as a result our results of operations.

Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.

Because our operations depend on the demand for oil and used oil, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil, gas and oil and gas related products could have a material adverse impact on our business, financial condition and results of operations. We also face competition from competing energy sources, such as renewable energy sources.

Competition due to advances in renewable fuels may lessen the demand for our products and negatively impact our profitability.

Alternatives to petroleum-based products and production methods are continually under development. For example, a number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean-burning gaseous fuels that may address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns, which if successful could lower the demand for oil and gas. If these non-petroleum-based products and oil alternatives continue to expand and gain broad acceptance such that the overall demand for oil and gas is decreased, it could have an adverse effect on our operations and the value of our assets.

Future litigation or governmental proceedings could result in material adverse consequences, including judgments or settlements.

From time to time, we are involved in lawsuits, regulatory inquiries and may be involved in governmental and other legal proceedings arising out of the ordinary course of our business. Many of these matters raise difficult and complicated factual and legal issues and are subject to uncertainties and complexities. The timing of the final resolutions to these types of matters is often uncertain. Additionally, the possible outcomes or resolutions to these matters could include adverse judgments or settlements, either of which could require substantial payments, adversely affecting our results of operations and liquidity.

We may be subject in the normal course of business to judicial, administrative or other third-party proceedings that could interrupt or limit our operations, require expensive remediation, result in adverse judgments, settlements or fines and create negative publicity.

Governmental agencies may, among other things, impose fines or penalties on us relating to the conduct of our business, attempt to revoke or deny renewal of our operating permits, franchises or licenses for violations or alleged violations of environmental laws or regulations or as a result of third-party challenges, require us to install additional pollution control equipment or require us to remediate potential environmental problems relating to any real property that we or our predecessors ever owned, leased or operated or any waste that we or our predecessors ever collected, transported, disposed of or stored. Individuals, citizens groups, trade associations or environmental activists may also bring actions against us in connection with our operations that could interrupt or limit the scope of our business. Any adverse outcome in such proceedings could harm our operations and financial results and create negative publicity, which could damage our reputation, competitive position and stock price. We may also be required to take corrective actions, including, but not limited to, installing additional equipment, which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against us. These could result in a material adverse effect on our prospects, business, financial condition and our results of operations.

Approximately 50% of our Colorado, New Mexico, and Wyoming properties, are undeveloped; therefore, the risk associated with our success is greater than would be the case if the majority of such properties were categorized as proved developed producing.

Because approximately 50% of our Colorado, New Mexico, and Wyoming properties, are undeveloped, we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

Part of our strategy involves drilling in existing or emerging oil and gas plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Our operations in the Permian Basin in Chaves and Roosevelt Counties, New Mexico, the D-J Basin in Weld and Morgan Counties, Colorado, and the PRB in Laramie and Campbell Counties, Wyoming, involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and therefore generate the highest possible returns. The additional risks that we face while drilling horizontally include, but are not limited to, the following:

Risks that we face while completing our wells include, but are not limited to, the following:

The results of our drilling in new or emerging formations will be more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and NGLs decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled to prospects that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage of our reserves are undeveloped. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data obtained by analyzing other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.

The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. An economy-wide transition to lower GHG energy sources could have a variety of adverse effects on our operations and financial results.

Many scientists have shown that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth’s atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such events were to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.

Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. As a result, if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Efforts by governments, international bodies, businesses and consumers to reduce GHGs and otherwise mitigate the effects of climate change are ongoing. The nature of these efforts and their effects on our business are inherently unpredictable and subject to change. Certain regulatory responses to climate change issues are discussed above under the headings “Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Colorado forced pooling system and drilling operation set-back rules, salt water disposal permitting regulations in New Mexico or Wyoming, and new federal orders restricting operations on federal lands, could have a material adverse effect on our business” and “New or amended environmental legislation or regulatory initiatives could result in increased costs, additional operating restrictions, or delays, or have other adverse effects on us” and in Item 1 - Business – Regulation in the Oil and Gas Industry. However, actions taken by private parties in anticipation of, or to facilitate, a transition to a lower-GHG economy will affect us as well. For example, our cost of capital may increase if lenders or other market participants decline to invest in fossil fuel-related companies for regulatory or reputational reasons. Similarly, increased demand for low-carbon or renewable energy sources from consumers could reduce the demand for, and the price of, the products we produce. Technological changes, such as developments in renewable energy and low-carbon transportation, could also adversely affect demand for our products.

The requirements, restrictions and covenants in our A&R Credit Agreement, including interest payable thereunder, may restrict our ability to operate our business and might lead to a default under such agreement.

Borrowings under the A&R Credit Agreement may be alternate base rate (“ABR”) loans or SOFR loans, at the election of the Company. Interest is payable quarterly for ABR loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at the forward-looking term rate based on the secured overnight financing rate as administered by the Federal Reserve Bank of New York (“SOFR”) for a one, three or six-month interest period plus an applicable margin ranging from 300 to 400 basis points, depending on the percentage of the borrowing base utilized, plus an additional 10 basis point credit spread adjustment (the “SOFR Rate”). ABR loans bear interest at a rate per annum equal to the greatest of: (i) the prime rate as publicly announced by Citibank; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted forward-looking term rate based on SOFR for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 200 to 300 basis points, depending on the percentage of the borrowing base utilized (the “ABR Rate”). The Company also pays a commitment fee on unused commitment amounts under its facility of 37.5 basis points or 50 basis points, depending on the percentage of the borrowing base utilized. The Company may repay any amounts borrowed under the A&R Credit Agreement prior to the maturity date without any premium or penalty, and is required to repay certain portions of the amounts borrowed under the A&R Credit Agreement upon the occurrence of certain events.

The A&R Credit Agreement includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Company from creating any indebtedness without the consent of the Lenders, subject to certain exceptions, and the maintenance of the following financial ratios: (i) a current ratio, which is the ratio of the Company’s consolidated current assets (including unused commitments under the A&R Credit Agreement and excluding non- cash derivative assets) to its consolidated current liabilities (excluding the current portion of long-term debt under the A&R Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and (ii) a leverage ratio, which is the ratio of Total Net Debt to EBITDAX (each as defined in the A&R Credit Agreement) for the prior four fiscal quarters, of not greater than 3.0 to 1.0.  The Company is required to hedge at least 75% of its projected proved developed producing reserves (PDP) oil and gas production at the time of entry into the A&R Credit Agreement, for the first 24 months of the agreement, and 50% of its projected PDP of oil and gas production for months 25-36. Afterward, within 60 days after each fiscal quarter, the Company must show it has hedged at least 50% of expected oil and gas production for the next 18 months. The Company may hedge crude oil, natural gas, or natural gas liquids (on a barrel of oil equivalent basis) to meet these requirements, but may not hedge more than 75% of anticipated production (on a barrel of oil equivalent basis) for any month.

In addition, the A&R Credit Agreement is subject to customary events of default for a facility of that size and type, including a change in control. If an event of default occurs and is continuing, the administrative agent may, with the consent of majority lenders, or shall, at the request of the majority lenders, accelerate any amounts outstanding and terminate lender commitments and declare the entire amount of obligations owed under the A&R Credit Agreement immediately due and payable and take certain other actions provided for under the A&R Credit Agreement.

As a result of these requirements, covenants and limitations, we may not be able to respond to changes in business and economic conditions and to obtain additional financing, if needed, and we may be prevented from engaging in transactions that might otherwise be beneficial to us. The breach of any of these requirements or covenants could result in a default under the A&R Credit Agreement or future credit facilities. Upon the occurrence of an event of default, the lenders could elect to declare all amounts outstanding under such A&R Credit Agreement or future debt facilities, including accrued interest or other obligations, to be immediately due and payable. If amounts outstanding under such A&R Credit Agreement or future debt facilities were to be accelerated, our assets might not be sufficient to repay in full that indebtedness and our other indebtedness.

A prolonged period of weak, or a significant decrease in, industry activity and overall markets may make it difficult to comply with our covenants and the other restrictions in the agreements governing our debt and current global and market conditions have increased the potential for that difficulty.

As of the date of this Report, the A&R Credit Agreement has a balance of $98.0 million. Amounts, if any, that we borrow under the A&R Credit Agreement, are due on October 31, 2029.

Our obligations under the A&R Credit Agreement are secured by a first priority security interest in substantially all of our assets and various Company guarantees.

The amounts borrowed pursuant to the terms of the A&R Credit Agreement are secured by substantially all of the present and after-acquired assets of the Company and its subsidiaries. Additionally, certain of our subsidiaries have guaranteed the amounts due, and obligations under, the A&R Credit Agreement.

As a result of the above, our creditors, in the event of the occurrence of a default under the A&R Credit Agreement, may enforce their security interests over our assets and/or our subsidiaries which secure such obligations, may take control of our assets and operations, force us to seek bankruptcy protection, or force us to curtail or abandon our current business plans and operations. If that were to happen, any investment in the Company (including, but not limited to, any investment in our common stock) could become worthless.

Continued increases in interest rates will cause our debt service obligations to increase and may have an adverse effect on our operations.

The amounts borrowed under the A&R Credit Agreement bear interest at either the SOFR Rate or the ABR Rate. Interest rates have recently been subject to increasing volatility and any increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations. In addition, a future increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

Changes in interest rates could also have a material adverse impact on our earnings and cash flows. Because our future notes payable are expected to have variable interest rates, our business results are expected to be subject to fluctuations in interest rates. Changes in market interest rates may influence our financing costs, returns on financial investments and the valuation of derivative contracts and could reduce our earnings and cash flows.

Risks Related to Management, Employees and Directors

Potential conflicts of interest could arise for certain members of our management team that hold management positions with other entities and our largest stockholder.

Mr. J. Douglas Schick, our President and Chief Executive Officer and a member of the board, Clark R. Moore, our Executive Vice President, General Counsel and Secretary, and Mr. Reagan Dukes, our Chief Operating Officer, and various of our directors, including Josh Schmidt, our Chairman and Edward Geiser, hold various other management positions with privately-held companies, some of which are involved in the oil and gas industry. We believe these positions require only an immaterial amount of each applicable officer’s time and will not conflict with the roles of our officers or directors, their or responsibilities with our company. If any of these companies enter into one or more transactions with our company, or if the officer’s or director’s position with any such company requires significantly more time than currently anticipated, potential conflicts of interests could arise from the officers or directors performing services for us and these other entities.

Additionally, pursuant to our Amended and Restated Certificate of Formation, the Juniper Shareholder and its affiliates (the “Juniper Investor Group”, which term includes the Juniper Directors) and Dr. Simon Kukes and his affiliates (collectively, the “PED Investor Group”), may each engage in other business ventures, including those that compete with or overlap with our business. Each group may hold positions, invest in, or develop opportunities related to other entities (“Other Investments”), potentially creating conflicts of interest. Pursuant to the Amended and Restated Certificate of Formation, the Company explicitly waives any right or expectation to participate in certain described corporate opportunities including businesses that may compete with, overlap with, complement, or otherwise be suitable for the Company or its subsidiaries and agrees that neither the investor groups, nor their representatives or directors, are obligated to share or offer these opportunities to the Company, unless the opportunity arises solely from their role as a director of the Company or through specific information rights in the Shareholder Agreement (“Renounced Business Opportunities”). However, the Company remains free to pursue any such renounced opportunities on its own.

The provisions in our Amended and Restated Certificate of Formation permitting the Juniper Investor Group and the PED Investor Group to engage in other business activities, including those that may compete with or overlap with our business, could result in conflicts of interest and limit our access to attractive business opportunities. Because these investors and their affiliated directors are not restricted from pursuing competing ventures or investments, they may allocate time, resources and opportunities to other entities in which they have an interest, which could adversely affect our ability to compete effectively or pursue strategic initiatives.

We depend significantly upon the continued involvement of our present management.

We depend to a significant degree upon the involvement of our management, specifically, our President and Chief Executive Officer, and member of the board, Mr. J. Douglas Schick. Our performance and success are dependent to a large extent on the efforts and continued employment of Mr. Schick. We do not believe that Mr. Schick could be quickly replaced with personnel of equal experience and capabilities, and his successor(s) may not be as effective. If Mr. Schick or any of our other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. Mr. Schick is party to an employment agreement with us which has no stated term and can be terminated by either party without cause.

We have an active Board of Directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.

Juniper beneficially owns 52% of our common stock, which gives Juniper majority voting control over stockholder matters and Juniper’s interests may be different from your interests; and as a result of such ownership, we are a “controlled company” under applicable NYSE American rules.

Juniper beneficially owns approximately 52% of our issued and outstanding common stock. As such, Juniper can control the outcome of all matters requiring a stockholder vote, including the election of directors, the adoption of amendments to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions.  In addition, Juniper is entitled to appoint, and has appointed, three of the six members of the Company's Board of Directors pursuant to the Shareholder Agreement.  Subject to any fiduciary duties owed to the stockholders generally, while Juniper’s interests may generally be aligned with the interests of our stockholders, in some instances Juniper may have interests different than the rest of our stockholders, including but not limited to, future potential company financings in which Juniper may participate. Juniper also has significant influence on our Board of Directors due to appointment of three of the six current members of the Company’s Board.  Juniper’s influence or control of our company as a stockholder and through its Board appointments may have the effect of delaying or preventing a change of control of our company and may adversely affect the voting and other rights of other stockholders. Because Juniper controls the stockholder vote, investors will not be able to replace its appointees to the Board of Directors and may also not be able to replace other appointees, if they disagree with the way our business is being operated. Additionally, the interests of Juniper may differ from the interests of the other stockholders and thus result in corporate decisions that are adverse to other stockholders. Due to Juniper’s ownership of the Company, as discussed above, we are a “controlled company” under the rules of the NYSE American. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and, as such, can elect to be exempt from certain corporate governance requirements, including requirements that:

As a “controlled company,” we may elect to rely on some or all of these exemptions, provided that we have to date not taken advantage of any of these exemptions and do not currently intend to take advantage of any of these exemptions moving forward. Notwithstanding that, should the interests of Juniper differ from those of other stockholders, the other stockholders may not have the same protections afforded to stockholders of companies that are subject to all of the NYSE American corporate governance standards. Even if we do not avail ourselves of these exemptions, our status as a controlled company could make our common stock less attractive to some investors or otherwise harm our stock price.

The Shareholder Agreement provides that the Board will consist of six directors or such other number as approved by the Board in accordance with the organizational documents of the Company and the Shareholder Agreement and be constituted as follows:

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 nomination of such Juniper Directors is subject to such persons not being prohibited from serving as a member of the Board. In the event any Juniper Director ceases serving as a member of the Board for any reason, the Juniper Shareholder has the right to designate a replacement, and subject to certain customary exceptions, the Board is required to take all reasonable actions within its control to appoint such replacement person as a member of the Board of the Company to fill such vacancy. The Juniper Shareholder also has the right to remove any Juniper Director at any time for any reason.

The Board is prohibited from increasing or decreasing the number of members of the Board without the affirmative vote of a majority of the independent directors then on the Board that are not Juniper Directors, and the written consent of the Juniper Shareholder.

In some instances, affiliates of Juniper may have interests different than the rest of our shareholders. The influence or control of our Company by such persons may have the effect of delaying or preventing a change of control of our Company and may adversely affect the voting and other rights of other shareholders. Additionally, the interests of such persons may differ from the interests of the other shareholders and thus result in corporate decisions that are adverse to other shareholders.

In addition, this concentration of ownership might adversely affect the market price of our common stock by: (1) delaying, deferring or preventing a change of control of our Company; (2) impeding a merger, consolidation, takeover or other business combination involving our Company; or (3) discouraging a potential acquirer from making a tender offer or otherwise attempting to obtain control of our Company. Because of the ownership of securities of Juniper, investors may find it difficult to replace our current directors (and such persons as they may appoint from time to time) as members of our management if they disagree with the way our business is being operated. Additionally, the interests of Juniper may differ from the interests of the other stockholders and thus result in corporate decisions that are adverse to other stockholders.

Risks Relating to Government Regulations

New or revised rules, regulations and policies may be issued, and new legislation may be proposed, that could impact the oil and gas exploration and production industry.

New or revised rules, regulations and policies may be issued, and new legislation may be proposed, that could impact the oil and gas exploration and production industry. Such rules, regulations, policies and legislation may affect, among other things, (i) permitting for oil and gas drilling on state, tribal and federal lands; (ii) the leasing of state, tribal and federal lands for oil and gas development; (iii) the regulation and disclosure of greenhouse gas emissions and/or other climate change-related matters associated with oil and gas operations (e.g., the development, implementation and carrying out of carbon capture and storage activities, including associated financial or tax incentives); (iv) the use of hydraulic fracturing on state, tribal and federal lands; (v) the calculation of royalty payments in respect of oil and gas production from state, tribal and federal lands (including, but not limited to, an increase in applicable royalty percentages); (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies; and (vii) the use of financial derivative instruments to hedge the financial impact of fluctuations in crude oil, natural gas and NGLs prices.

For example, our business in the D-J Basin of Colorado utilizes a methodology available in Colorado known as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling spacing unit to apply to the Colorado Oil and Gas Conservation Commission for an order forcing all other holders of oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. In addition, our Permian Basin operations require significant salt water disposal capacity, with the permitting of necessary salt water disposal wells being regulated by the New Mexico State Land Office. In recent quarters, we have encountered significant delays in receiving such permits, and increasing difficulty in obtaining required permits, from the New Mexico State Land Office, which has delayed completion operations and the bringing of new wells on to full production. Changes in the legal and regulatory environment governing our industry, particularly any changes to Colorado’s forced pooling procedures that make forced pooling more difficult to accomplish and changes in minimum set-backs distances for drilling operations from buildings (including those recently adopted), or increased regulation in New Mexico or Wyoming with respect to salt water disposal well permitting, could result in increased compliance costs and operational delays, and adversely affect our business, financial condition and results of operations.

In addition, approximately 17% of the Company’s acreage in New Mexico, 1% of the Company’s acreage in Colorado, and 66% of the Company’s acreage in Wyoming is located on federal lands, which may be subject to federal laws, regulations and orders that could limit our ability to operate. For example, on January 20, 2021, the Acting Secretary of the Interior issued Order Number 3395 (“Order No. 3395”) which contained a directive to temporarily halt all federal permitting activity for 60 days in an effort to study environmental impacts of oil and gas drilling and development, which a federal court blocked with a preliminary injunction in June 2021.  President Biden subsequently announced that his administration will resume onshore oil and gas lease sales on federal lands effective April 18, 2022. While this had no impact on existing or ongoing operations, potentially subsequent federal orders could restrict our ability to develop our leases on federal lands, which could adversely affect our business, financial condition and results of operations.

Further, drilling long lateral wells in Wyoming typically involves interception and development of multiple federal leases. However, for several years, the federal government, through the BLM, has limited the number of minerals acres made available for lease. As a result, many operators suffer from leasehold “gaps” in their drilling units, which effectively prohibit these operators from developing their existing federal leasehold at no-fault of the operator. Section 39 allows for the suspension of operations and production on leases when the necessary federal tracts for exploration and development are not yet available. Section 39 suspense must be requested annually. Certain of the leases owned by the Company in the PRB have been “placed in suspense” under Section 39. The ability of the Company to effectively develop these leases is subject to its ability to close existing “gaps” in its federal leasehold by leasing additional acreage from the BLM.

In the event that federal, state or local restrictions or prohibitions are adopted in areas where we conduct operations, that restrict operations or otherwise 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.

New or amended environmental legislation or regulatory initiatives could result in increased costs, additional operating restrictions, or delays, or have other adverse effects on us.

The environmental laws and regulations to which we are subject change frequently, often to become more burdensome and/or to increase the risk that we will be subject to significant liabilities. New or amended federal, state, or local laws or implementing regulations or orders imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of resources (especially from shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products. Any such outcome could have a material and adverse impact on our cash flows and results of operations.

For example, in 2014, 2016 and 2018, opponents of hydraulic fracturing sought statewide ballot initiatives in Colorado that would have restricted oil and gas development in Colorado and could have had materially adverse impacts on us. One of the proposed initiatives would have made the vast majority of the surface area of the state ineligible for drilling, including substantially all of our planned future drilling locations. By further example, in April 2019, Colorado Senate Bill 19-181 (the “Bill”) was passed into law, which prioritizes the protection of public safety, health, welfare, and the environment in the regulation of the oil and gas industry by modifying the State’s oil and gas statutes and clarifying, reinforcing, and establishing local governments’ regulatory authority over the surface impacts of oil and gas development in Colorado. This Bill, among other things, gives more power to local government entities in making land use decisions about oil and gas development and regulation, and directs the ECMC (formerly the COGCC)) to promulgate rules to ensure, among other things, proper wellbore integrity, allow public disclosure of flowline information, and evaluate when inactive or shut-in wells must be inspected before being put into production or used for injection. In addition, the Bill requires that owners of more than 50% of the mineral interests in lands to be pooled must have joined in the application for a pooling order and that the application must include proof that the applicant received approval for the facilities from the affected local government or that the affected local government does not regulate such facilities. In addition, the Bill provides that an operator cannot use the surface owned by a nonconsenting owner without permission from the nonconsenting owner, and increases nonconsenting owners’ royalty rates during a well’s pay-back period from 12.5% to 13.0%. Pursuant to the Bill, the COGCC (now the ECMC) conducted a series of rulemaking hearings during 2020 which resulted in updated regulatory and permitting requirements, including siting requirements. The COGCC (now the ECMC) commissioners determined that locations with residential or high occupancy building units within 2,000 feet would be subject to additional siting requirements, but also supported “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. We anticipate that the Bill may make it more difficult and more costly for us to undertake oil and gas development activities in Colorado, although the Company has not experienced any significant additional difficulties or costs to date as a result of the Bill.

Similar to the Bill described above, proposals are made from time to time to adopt new, or amend existing, laws and regulations to address hydraulic fracturing or climate change concerns through further regulation of exploration and development activities. Please read “Part I” – “Item 1. Business” — “Regulation of the Oil and Gas Industry” and “Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us. We cannot predict the nature, outcome, or effect on us of future regulatory initiatives, but such initiatives could materially impact our results of operations, production, reserves, and other aspects of our business.

For example, in 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment (“Denver Metro/North Front Range NAA”) area from “moderate” to “serious” under the 2008 national ambient air quality standard. This increase in non-attainment status to “serious” triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in December 2020 that are applicable to our operations, with additional obligations for the state under the CAA possible that could result in new and more stringent air quality permitting and control requirements, which may in turn result in significant costs and delays in obtaining necessary permits applicable to our operations. 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. 

The Federal Government previously instituted a moratorium on new oil and gas leases and permits on federal onshore and offshore lands, which may have a material adverse effect on the Company and its results of operations.

On January 20, 2021, the Acting U.S. Interior Secretary, instituted a moratorium on new oil and gas leases and permits on federal onshore and offshore lands, which a federal court blocked with a preliminary injunction in June 2021.  President Biden subsequently announced that his administration will resume onshore oil and gas lease sales on federal lands effective April 18, 2022. A total of approximately 17% of the Company’s acreage in New Mexico, 1% of the Company’s acreage in Colorado, and 66% of the Company’s acreage in Wyoming is located on federal lands. It is currently unclear whether the moratorium will be reinstated, or whether such moratorium is the start of a change in federal policies regarding the grant of oil and gas permits on federal lands. If such prior moratorium was to become permanent, or the federal government in the future were to grant less permits on federal lands, make such permitting process more difficult, costly, or to institute more stringent rules relating to such permitting process, it could have a material adverse effect on the value of the Company’s leases and/or its ability to undertake oil and gas operations on such the portion of its leases on federal lands.

SEC rules could limit our ability to book additional proved undeveloped reserves (“PUDs”) in the future.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.

From time to time, legislative proposals are made that would, if enacted, result in the elimination of the immediate deduction for intangible drilling and development costs, the elimination of the deduction from income for domestic production activities relating to oil and gas exploration and development, the repeal of the percentage depletion allowance for oil and gas properties, and an extension of the amortization period for certain geological and geophysical expenditures. Such changes, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

We may incur substantial costs to comply with the various federal, state, and local laws and regulations that affect our oil and natural gas operations, including as a result of the actions of third parties.

We are affected significantly by a substantial number of governmental regulations relating to, among other things, the release or disposal of materials into the environment, health and safety, land use, and other matters. A summary of the principal environmental rules and regulations to which we are currently subject is set forth in “Part I” – “Item 1. Business” — “Regulation of the Oil and Gas Industry” and “Regulation of Environmental and Occupational Safety and Health Matters”. Compliance with such laws and regulations often increases our cost of doing business and thereby decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.

The environmental laws and regulations to which we are subject may, among other things:

In addition, we could face liability under applicable environmental laws and regulations as a result of the activities of previous owners of our properties or other third parties. For example, over the years, we have owned or leased numerous properties for oil and natural gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including The Comprehensive Environmental Response, Compensation, and Liability Act - otherwise known as CERCLA or Superfund, and state laws, we could be held liable for the removal or remediation of previously released materials or property contamination at such locations, or at third-party locations to which we have sent waste, regardless of our fault, whether we were responsible for the release or whether the operations at the time of the release were lawful.

Compliance with, or liabilities associated with violations of or remediation obligations under, environmental laws and regulations could have a material adverse effect on our results of operations and financial condition.

Regulations could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

Rules adopted by federal regulators establishing federal regulation of the over-the-counter (“OTC”) derivatives market and entities that participate in that market may adversely affect our ability to manage certain of our risks on a cost-effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our oil and gas.

We expect that our potential future hedging activities will remain subject to significant and developing regulations and regulatory oversight. However, the full impact of the various U.S. regulatory developments in connection with these activities will not be known with certainty until such derivatives market regulations are fully implemented and related market practices and structures are fully developed.

We have identified material weaknesses in our disclosure controls and procedures and internal control over financial reporting. If not remediated, our failure to establish and maintain effective disclosure controls and procedures and internal control over financial reporting could result in material misstatements in our financial statements and a failure to meet our reporting and financial obligations, each of which could have a material adverse effect on our financial condition and the trading price of our common stock.

Maintaining effective internal control over financial reporting and effective disclosure controls and procedures are necessary for us to produce reliable financial statements. As reported under “Part II” - “Item 9A. Controls and Procedures”, as of December 31, 2025, our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) have determined that our disclosure controls and procedures were not effective. Separately, management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025 and determined that such internal control over financial reporting was not effective as a result of such assessment, and such internal control over financial reporting.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. A control deficiency exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis.

Through the course of the Company’s preparation of its year-ended December 31, 2025 financial statements, a material weakness in our internal control over financial reporting was extended which also related to the review of our inputs to the depreciation, depletion, and amortization calculations, specifically that we did not have effective controls over the proper segregation of total proved reserves and total proved developed reserves in the depletable base of our leasehold and drilling costs calculation, and we did not accurately include the correct inputs in our depletion calculations related to our acquired properties per the Mergers. We have already developed a plan to implement new controls and procedures designed to address the identified material weakness. The Company believes these new controls and procedures will remediate the material weaknesses in a future period. However, there is the potential that the Company’s already implemented efforts to remedy the material weakness will be ineffective and/or that additional material weaknesses could occur regardless of the remediation or additional controls implemented by the Company.

Maintaining effective disclosure controls and procedures and effective internal control over financial reporting are necessary for us to produce reliable financial statements and the Company is committed to remediating its material weaknesses in such controls as promptly as possible. However, there can be no assurance as to when these material weaknesses will be remediated or that additional material weaknesses will not arise in the future. Any failure to remediate the material weaknesses, or the development of new material weaknesses in our internal control over financial reporting, could result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a material adverse effect on our financial condition and the trading price of our common stock, and/or result in litigation against us or our management. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or facilitate the fair presentation of our financial statements or our periodic reports filed with the SEC.

We have previously concluded that certain of our previously issued financial statements should not be relied upon and have restated certain of our previously issued financial statements which may affect investor confidence and raise reputational issues and may subject us to additional risks and uncertainties, including increased professional costs and the increased possibility of legal proceedings and regulatory inquiries.

As previously disclosed, on March 28, 2025, the Audit Committee of the Board, after discussion with the Company’s senior management and the Company’s then independent registered public accounting firm, Marcum LLP (“Marcum”), concluded that the Company’s previously issued audited financial statements included in the Company’s (i) audited consolidated financial statements as of and for the fiscal year ended December 31, 2023, originally included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023 (the “2023 10-K”), and (ii) audited consolidated financial statements as of and for the fiscal year ended December 31, 2022, originally included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 (the “2022 10-K”)(collectively, the “Form 10-Ks”) filed with the Commission  on March 18, 2024 and March 29, 2023, respectively, should no longer be relied upon and should be restated due to errors in the accounting for the depletion expense related to the Company’s oil and gas properties. These errors led to an overstatement of depletion expense during the impacted periods. Additionally, on October 27, 2025, the Audit Committee, after discussion with the Company’s senior management and the Company’s former independent registered public accounting firm, Marcum, which audited the Company’s financial statements for the year ended December 31, 2024, concluded that the Company’s previously issued audited financial statements included in the Company’s audited consolidated financial statements as of and for the fiscal year ended December 31, 2024, originally included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024 filed with the Commission on March 31, 2025, should no longer be relied upon and should be restated due to an error in the accounting for the prior period net operating losses in the calculation of the tax provision for the impacted period. This error resulted in an overstatement of the Company’s tax benefit and deferred income tax account during the impacted period. All of the prior financial statements which included errors have since been restated and such restatements have been included in the financial statements included in this Annual Report.

As a result of the errors discussed above and the resulting restatements of our consolidated financial statements for the impacted periods, we have incurred, and may continue to incur, unanticipated costs for accounting, legal and other professional fees in connection with or related to the restatement, and have become subject to a number of additional risks and uncertainties. These include, among other things, an increased risk of shareholder litigation, including securities class actions and derivative lawsuits, as well as regulatory inquiries and investigations. Any such litigation or inquiries could result in substantial costs, diversion of management’s attention, and potential adverse judgments, settlements or penalties. In addition, these matters may adversely affect investor confidence in the accuracy of our financial disclosures and raise reputational risks for our business, either of which could harm our business, financial condition and results of operations.

Risks Related to Our Common Stock

We currently have a sporadic and volatile market for our common stock, and the market for our common stock is and may remain sporadic and volatile in the future.

We currently have a highly sporadic and volatile market for our common stock, which market is anticipated to remain sporadic and volatile in the future. Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:

Our common stock is listed on the NYSE American under the symbol “PED.” Our stock price may be impacted by factors that are unrelated or disproportionate to our operating performance. The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Additionally, general economic, political and market conditions, such as recessions, interest rates or international currency fluctuations may adversely affect the market price of our common stock. Due to the limited volume of our shares which trade, we believe that our stock prices (bid, ask and closing prices) may not be related to our actual value, and not reflect the actual value of our common stock. Stockholders and potential investors in our common stock should exercise caution before making an investment in us.

Additionally, as a result of the potential illiquidity and sporadic trading of our common stock, investors may not be interested in owning our common stock because of the inability to acquire or sell a substantial block of our common stock at one time. This may have an adverse effect on the market price of our common stock. In addition, a stockholder may not be able to borrow funds using our common stock as collateral because lenders may be unwilling to accept the pledge of securities having such a limited market. We cannot assure you that an active trading market for our common stock will develop or, if one develops, that it will be sustained.

An active and sustained trading market for our common stock may not develop in the future.

Our common stock currently trades on the NYSE American, although our common stock’s trading volume has been low from time to time and trading in our common stock has historically been sporadic. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. However, our common stock may continue to have a sporadic trading volume, and investors may not be interested in owning our common stock because of the inability to acquire or sell a substantial block of our common stock at one time. This could have an adverse effect on the market price of our common stock. In addition, a stockholder may not be able to borrow funds using our common stock as collateral because lenders may be unwilling to accept the pledge of securities having such a limited market. We cannot assure you that an active trading market for our common stock will develop or, if one develops, be sustained.

Our outstanding options may adversely affect the trading price of our common stock.

As of December 31, 2025, there are outstanding stock options to purchase 104,200 shares of our common stock at a weighted average price per share of $20.09. For the life of the options, the holders have the opportunity to profit from a rise in the market price of our common stock without assuming the risk of ownership. The issuance of shares upon the exercise of outstanding securities will also dilute the ownership interests of our existing stockholders.

The availability of these shares for public resale, as well as any actual resales of these shares, could adversely affect the trading price of our common stock. We previously filed registration statements with the SEC on Form S-8 providing for the registration of an aggregate of approximately 1,056,745 shares of our common stock, issued, issuable or reserved for issuance under our equity incentive plans. Subject to the satisfaction of vesting conditions, the expiration of lockup agreements, any management 10b5-1 plans and certain restrictions on sales by affiliates, shares registered under registration statements on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock pursuant to the exercise of outstanding options or conversion of other securities, or the effect, if any, that future issuances and sales of shares of our common stock may have on the market price of our common stock. Sales or distributions of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may cause the market price of our common stock to decline.

We are subject to the Continued Listing Criteria of the NYSE American and our failure to satisfy these criteria may result in delisting of our common stock.

Our common stock is currently listed on the NYSE American. For continued listing on the NYSE American, we must maintain certain share prices, financial and share distribution targets, including maintaining a minimum amount of shareholders’ equity ($2 million if we have reported losses from continuing operations and/or net losses in two of the prior three years; $4 million if we have reported losses from continuing operations and/or new losses in three of the last four fiscal years; and $6 million if we have losses from continuing operations and/or net losses in the last five fiscal years), a minimum market value ($1 million) and a minimum number of public shareholders (300), subject to certain exceptions. In addition to these objective standards, the NYSE American may delist the securities of any issuer if, in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; if it appears that the extent of public distribution or the aggregate market value of the security has become so reduced as to make continued listing on the NYSE American inadvisable; if the issuer sells or disposes of principal operating assets or ceases to be an operating company; if an issuer fails to comply with the NYSE American’s listing requirements; if an issuer’s common stock sells at what the NYSE American considers a “low selling price ” (generally trading below $0.20 per share for an extended period of time) and the issuer fails to correct this via a reverse split of shares after notification by the NYSE American (provided that issuers can also be delisted if any shares of the issuer trade below $0.06 per share); or if any other event occurs or any condition exists which makes continued listing on the NYSE American, in its opinion, inadvisable. Finally, NYSE American rules require us, as long as we remain a smaller reporting company, to maintain at least 50% independent directors and to have an audit committee of at least two persons, subject to controlled company exceptions.

If the NYSE American delists our common stock, investors may face material adverse consequences, including, but not limited to, a lack of trading market for our securities, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional financing to fund our operations.

Due to the fact that our common stock is listed on the NYSE American, we are subject to financial and other reporting and corporate governance requirements which increase our costs and expenses.

We are currently required to file annual and quarterly information and other reports with the Securities and Exchange Commission that are specified in Sections 13 and 15(d) of the Exchange Act. Additionally, due to the fact that our common stock is listed on the NYSE American, we are also subject to the requirements to maintain independent directors, comply with other corporate governance requirements and are required to pay annual listing and stock issuance fees. These obligations require a commitment of additional resources including, but not limited, to additional expenses, and may result in the diversion of our senior management’s time and attention from our day-to-day operations. These obligations increase our expenses and may make it more complicated or time consuming for us to undertake certain corporate actions due to the fact that we may require NYSE approval for such transactions and/or NYSE rules may require us to obtain stockholder approval for such transactions.

Risks Associated with Our Governing Documents and Texas Law

Our Certificate of Formation and Bylaws provide for indemnification of officers and directors at our expense, which may result in a major cost to us and hurt the interests of our stockholders because corporate resources may be expended for the benefit of officers or directors.

Our Certificate of Formation and bylaws authorize us to indemnify and hold harmless, to the fullest extent permitted by applicable law, each person who is or was made a party or is threatened to be made a party to or is otherwise involved in any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative by reason of the fact that he or she is or was a director or officer of the Company or, while a director or officer of the Company, is or was serving at the request of the Company. These indemnification obligations may result in a major cost to us and hurt the interests of our stockholders because corporate resources may be expended for the benefit of officers or directors.

We have been advised that, in the opinion of the SEC, indemnification for liabilities arising under federal securities laws is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification for liabilities arising under federal securities laws, other than the payment by us of expenses incurred or paid by a director, officer or controlling person in the successful defense of any action, suit or proceeding, is asserted by a director, officer or controlling person in connection with our activities, we will (unless in the determination of our counsel, the matter has been settled by controlling precedent) submit to a court of appropriate jurisdiction, the question whether indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. The legal process relating to this matter if it were to occur is likely to be very costly and may result in us receiving negative publicity, either of which factors is likely to materially reduce the market and price for our shares.

Our Certificate of Formation contains a specific provision that limits the liability of our directors for monetary damages to the Company and the Company’s stockholders.

Our Certificate of Formation provides that a director of the Company shall, to the fullest extent permitted by the Texas Business Organizations Code, as revised, as then may exist or as it may hereafter be amended, not be personally liable to the Company or its stockholders for monetary damages for breach of fiduciary duty as a director, except to the extent such exception from liability is not permitted under the Texas Business Organizations Code, as revised. The limitation of monetary liability against our directors under Texas law and the existence of indemnification rights to them may result in substantial expenditures by us and may discourage lawsuits against our directors, officers and employees. These provisions and resultant costs may also discourage us from bringing a lawsuit against our directors and officers for breaches of their fiduciary duties and may similarly discourage the filing of derivative litigation by our stockholders against our directors and officers, even though such actions, if successful, might otherwise benefit us and our stockholders.

Anti-takeover provisions in our Certificate of Formation and our Bylaws, as well as provisions of Texas law, might discourage, delay or prevent a change in control of our company or changes in our management and, therefore, depress the trading price of our securities.

Our Certificate of Formation and Bylaws and Texas law contain provisions that may discourage, delay or prevent a merger, acquisition or other change in control that stockholders may consider favorable, including transactions in which you might otherwise receive a premium for our securities. These provisions may also prevent or delay attempts by our stockholders to replace or remove our management. Our corporate governance documents include the following provisions: