PED 10-K
Pedevco Corp (PED)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ________________ to ____________
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Securities registered pursuant to Section 12(b) of the Act:
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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 ☐
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 ☐
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.
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).
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.
Large accelerated filer | ☐ | Accelerated filer | ☐ |
☒ | Smaller reporting company | ||
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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
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2024 (the last trading day of the registrant’s most recently completed second fiscal quarter), based upon the closing price of $0.9046 on June 28, 2024, the last reported trading price prior to such date, was approximately $
As of March 28, 2025,
DOCUMENTS INCORPORATED BY REFERENCE
None.
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EXPLANATORY NOTE
We are filing this comprehensive Annual Report on Form 10-K for the fiscal years ended December 31, 2024 and 2023 (“Comprehensive Form 10-K”). This Comprehensive Form 10-K contains our audited financial statements for the fiscal year ended December 31, 2024, as well as restatements of the following previously filed periods: (i) audited consolidated financial statements as of and for the fiscal year ended December 31, 2023, originally included in our 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 our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 (the “2022 10-K”)(collectively, the “Form 10-Ks” and the “Prior Financial Statements”).
Restatement of Previously Issued Consolidated Financial Statements
As previously disclosed in the Current Report on Form 8-K filed by the PEDEVCO Corp (the “Company”) with the Securities and Exchange Commission on March 25, 2025, in connection with the preparation of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, the Company concluded that in prior years it had not appropriately accounted for the depletion expense related to its oil and gas properties. These errors led to an overstatement of depletion expense during the impacted periods.
On March 28, 2025, the Audit Committee (the “Audit Committee”) of the Company’s Board of Directors, after discussion with senior management and the Company’s independent registered public accountants, concluded that the errors were material to the Company's Prior Financial Statements and the Prior Financial Statements as of and for the fiscal years ended December 31, 2023 and December 31, 2022, included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023, should no longer be relied upon due to the impact of the unintentional error noted above.
This Annual Report on Form 10-K includes restated Consolidated Financial Statements as of and for the years ended December 31, 2023 and 2022.
Refer to Note 4, Restatement of Previously Issued Consolidated Financial Statements, in the accompanying Consolidated Financial Statements included in Part II, Item 8 for additional information, including the impact on the specific accounts.
Restatement Overview
The following items have been restated, as appropriate, to correct the errors noted above:
| · | Part II - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations |
| · | Part II - Item 8. Financial Statements and Supplementary Data |
| · | Part IV - Item 15. Exhibits and Financial Statement Schedules |
Internal Control Considerations
Management determined that the restatement of our previously issued financial statements as described above indicates the existence of a material weakness in our internal control over financial reporting and that our internal control over financial reporting and disclosure controls and procedures were ineffective as of December 31, 2024. Management has created a plan of remediation to address the material weakness. See Item 9A in this Form 10-K for a further discussion of the material weakness in our internal control over financial reporting.
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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:
· | our business strategy; |
· | our reserves; |
· | our technology; |
· | our cash flows and liquidity; |
· | our financial strategy, budget, projections and operating results; |
· | oil and natural gas realized prices; |
· | timing and amount of future production of oil and natural gas; |
· | the availability of oil field labor; |
· | the amount, nature and timing of capital expenditures, including future exploration and development costs; |
· | drilling of wells; |
· | government regulation and taxation of the oil and natural gas industry; |
· | changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory developments, including in particular additional permit scrutiny in Colorado; |
· | exploitation projects or property acquisitions; |
· | costs of exploiting and developing our properties and conducting other operations; |
· | general economic conditions in the United States and around the world, including the effect of regional or global health pandemics (such as, for example, the 2019 coronavirus (“COVID-19”)), recent changes in inflation and interest rates, and risks of recessions, including as a result thereof; |
· | competition in the oil and natural gas industry; |
· | effectiveness of our risk management activities; |
· | environmental liabilities; |
· | counterparty credit risk; |
· | developments in oil-producing and natural gas-producing countries; |
· | political conditions in or affecting oil, NGLs and natural gas producing regions and/or pipelines, including in Eastern Europe, the Middle East and South America, for example, as experienced with the Russian invasion of the Ukraine in February 2022 and the current war in Israel, which conflicts are ongoing; |
· | our future operating results; |
· | future acquisition transactions; |
· | our estimated future reserves and the present value of such reserves; |
· | our plans, objectives, expectations and intentions contained in this Annual Report that are not historical; and |
· | those risks discussed under, or incorporated by reference in, “Risk Factors” below. |
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.
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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 2024 means the year ended December 31, 2024, whereas fiscal 2023 means the year ended December 31, 2023, and fiscal year 2022 means the year ended December 31, 2022.
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:
· | “Exchange Act” refers to the Securities Exchange Act of 1934, as amended; |
· | “SEC” or the “Commission” refers to the United States Securities and Exchange Commission; and |
· | “Securities Act” refers to the Securities Act of 1933, as amended. |
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.
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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.
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.
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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.
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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.
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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.
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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.
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 San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “Permian Basin”) and in the Denver-Julesberg Basin (“D-J Basin”) in Colorado and Wyoming. As of December 31, 2024, we held approximately 14,105 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, Pacific Energy Development Corp. (“PEDCO”), and which are operated by our wholly-owned operating subsidiary, Ridgeway Arizona Oil Corp. (“RAZO”), which asset we refer to as our “Permian Basin Asset.” Also as of December 31, 2024, we held approximately 18,669 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, through our wholly-owned subsidiary, PRH Holdings LLC (“PRH”), and which are operated by our wholly-owned operating subsidiary, Red Hawk Petroleum, LLC (“Red Hawk”), which asset we refer to as our “D-J Basin Asset.” As of December 31, 2024, we held interests in 35 gross (33.5 net) wells in our Permian Basin Asset, of which 28 gross (26.5 net) wells are active producers, five gross (five net) wells are inactive, and two gross (two net) wells are active salt water disposal wells (“SWD’s”), all of which are held by PEDCO and operated by RAZO, and interests in 82 gross (21.9 net) wells in our D-J Basin Asset held by PRH, all of which 17 gross (15.4 net) wells are operated by Red Hawk and currently producing, 48 gross (6.5 net) wells are non-operated, and 17 wells have an after-payout interest.
Business Strategy
We believe that horizontal development and exploitation of conventional assets in the Permian Basin and development of the Wattenberg and Wattenberg Extension in the D-J 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 other attractive onshore U.S. oil and gas assets that fit our acquisition criteria, that Company management believes can be developed using our technical and operating expertise and be accretive to stockholder value.
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Specifically, we seek to increase stockholder value through the following strategies:
· | Grow production, cash flow and reserves by developing our operated drilling inventory and participating opportunistically in non-operated projects. We believe our extensive inventory of drilling locations in the Permian Basin and the D-J Basin, combined with our operating expertise, will enable us to continue to deliver accretive production, cash flow and reserves growth. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base. |
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· | Apply modern drilling and completion techniques and technologies. We own and intend to acquire additional properties that have been historically underdeveloped and underexploited. We believe our attention to detail and application of the latest industry advances in horizontal drilling, completions design, frac intensity and locally optimal frac fluids will allow us to successfully develop our properties. |
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· | Optimization of well density and configuration. We own properties that are legacy oil fields characterized by widespread vertical and horizontal development and geological well control. We utilize the extensive geological, petrophysical and production data of such legacy properties to confirm optimal well spacing and configuration using modern reservoir evaluation methodologies. |
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· | Maintain a high degree of operational control and/or form partnerships which allow for a high degree of control over non-operated properties. We believe that by retaining operational control and/or by forming partnerships which require consent and input by all partners in major development projects, we can efficiently manage the timing and amount of our capital expenditures and operating costs, and thus key in on the optimal drilling and completions strategies, which we believe will generate higher recoveries and greater rates of return per well. |
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· | Leverage extensive deal flow, technical and operational experience to evaluate and execute accretive acquisition opportunities. Our management and technical teams have an extensive track record of forming and building oil and gas businesses. We also have significant expertise in successfully sourcing, evaluating and executing acquisition opportunities. We believe our understanding of the geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acreage in order to grow our reserve base and maximize stockholder value. |
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· | Preserve financial flexibility to pursue organic and external growth opportunities. We intend to maintain a disciplined financial profile in order to provide flexibility across various commodity and market cycles. |
We also are committed to developing and monitoring environmental, social and governance (“ESG”) initiatives and the Board of Directors plans to evaluate the potential adoption of ESG initiatives from time to time, provided that no definitive ESG plans have been adopted to date.
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 Permian Basin acreage so we can dictate the pace of development in order to execute our business plan. 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 net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million. This estimate includes a range of $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2.5 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses. We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and Area of Mutual Interest (“AMI”) entered into in August 2024 with a private operator. This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated. 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”).
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We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective. If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and nearly all held by production (“HBP”), allowing for flexibility of timing on development. Our 2025 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.
We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) equity infusions or loans (which may be convertible) made available from Dr. Simon G. Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, which funding Dr. Kukes is under no obligation to provide, (iv) public or private debt or equity financings, including up to $8.0 million in securities which we may sell in the future in “at the market offerings”, pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the “Lead Agent”), and A.G.P./Alliance Global Partners (“AGP” and, together with the Lead Agent, the “Agents”)(discussed in greater detail below under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing” (under which we have sold no shares to date), and (v) funding through credit or loan facilities, including under the Company’s reserve-based lending facility (“RBL”) with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $20 million and an aggregate maximum revolving credit amount of $250 million (of which none has been drawn down by the Company to date). In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2025.
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The following chart reflects our current organizational structure:
*Represents percentage of total voting power based on 91,339,385 shares of common stock outstanding as of March 28, 2025, with beneficial ownership calculated in accordance with Rule 13d-3 of the Exchange Act. Holdings of The SGK 2018 Revocable Trust are also included in holdings of Senior Management and the Board – See “Part III” — “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
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.
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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. Shallow conventional reservoirs (<8,000 feet) and short to mid-range laterals (1.0 mile and 1.5 mile, respectively) allow for efficient full-scale development without the requirement for extended reach laterals and large fracs to meet economic thresholds.
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 was recently appointed as our Chief Executive Officer effective January 1, 2025, 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. Also, our Executive Vice President and General Counsel, Clark R. Moore, has nearly 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 Executive Chairman, Dr. Simon G. Kukes, who brings over 40 years of experience in the oil industry, serving as our Chief Executive Officer from 2018 through 2024, and formerly serving as the CEO at Samara-Nafta, a joint venture with the U.S.-based international oil company Hess Corporation, CEO of Tyumen Oil Company (TNK), prior to its combination with British Petroleum, and as Chairman of Yukos Oil Company. In addition, our Board includes John J. Scelfo, who brings over 40 years of experience in oil and gas management, finance and accounting, and who served in numerous executive-level capacities at Hess Corporation, including as Senior Vice President, Finance and Corporate Development, Chief Financial Officer, Worldwide Exploration & Producing, and as a member of Hess’ Executive Committee. Our Board also includes H. Douglas Evans, who brings over 50 years of experience in executive management positions with Gulf Interstate Engineering Company, one of the world's top pipeline design and engineering firms, including as its Honorary Chairman and previously its Chairman and President and Chief Executive Officer, and who is a past President and Board member of the International Pipe Line and Offshore Contractors Association, former Chairman of its Strategy Committee, and formerly a member of the Pipeline Contractors Association.
Significant acreage positions and drilling potential. As of December 31, 2024, we have accumulated interests in a total of 14,105 net acres in our core Permian Basin Asset operating area, and 18,669 net acres in our core D-J Basin Asset operating area, both 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 Permian Basin Asset could contain up to 100 potential net 1.0 mile laterals wells on 160 acre spacing. We believe our D-J Basin Asset could contain up to 353 potential gross wells with 164 potential net wells, comprised of two gross 1.0-mile lateral wells with one net 1.0-mile lateral well, 351 gross 2.0-mile lateral wells with 163 net 2.0 mile lateral wells, on 80-acre spacing and 160-acre spacing, respectively, providing us with a substantial drilling inventory for future years. Not all of these potential well locations in our Permian Basin Asset and D-J Basin Asset are included in our reserve report due to SEC guidelines related to development timing.
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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, 2024, sales to three customers comprised 38%, 36% and 12%, 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.
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 for our D-J Basin Asset that is in effect until April 1, 2032. However, natural gas sales related to this agreement only represent less than 1% of our total revenues as of December 31, 2024, and the Company believes that this trend will continue in the D-J Basin Asset. 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.
Oil and Gas Properties
We believe that our Permian Basin and D-J 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 Northwest Shelf of the Permian Basin in Chaves and Roosevelt Counties, New Mexico, and the Wattenberg and Wattenberg Extension areas of Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, and elsewhere in the D-J Basin. 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 Permian Basin acreage so we can dictate the pace of development in order to execute our business plan. 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 net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million. This estimate includes a range of $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2.5 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses. We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and (AMI) entered into in August 2024 with a private operator. This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated. 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”).
Our Core Areas
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, 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 SWDs. As of December 31, 2024, 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.
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State of New Mexico
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In September 2023, the Company and Evolution Petroleum Corporation (“Evolution”) entered into a Participation Agreement (the “Participation Agreement”) for the joint development of a portion of the Company’s Permian Basin Asset known as the Chaveroo oilfield, located in Chaves and Roosevelt Counties, New Mexico (the “Chaveroo Field” and the “Chaveroo Farmout Transaction”). Pursuant to the Participation Agreement, the Company and Evolution identified twelve “Development Blocks” covering approximately 16,000 gross leasehold acres consisting of all leasehold rights from the surface to the base of the San Andres formation, where the Company currently holds leasehold interests (“Existing Leases”), in which the parties may jointly develop by drilling and completion of up to nine horizontal San Andres wells in each Development Block in accordance with the terms of the agreement, which terms include, but are not limited to: (i) Evolution made an initial payment of $366,000 to the Company in exchange for a 50% working interest share in the Existing Leases, covering the initial two Development Blocks (which equals Evolution’s share of the acreage portion for nine drilling locations therein); (ii) upon completion of the wells in each Development Block, Evolution will have the right, but not the obligation, to acquire a 50% working interest share in the next Development Block in exchange for the payment of $450 per net acre of Existing Leases held by the Company in such block, and participate on a 50% working interest share basis in the drilling and completion of up to nine horizontal San Andres wells in such Development Block; (iii) the parties entered into a standard operating agreement with the Company serving as the operator with respect to the development of the assets; (iv) if either party elects not to participate in the development of a Development Block, the other party may develop such Development Block independently with the non-participating party not required to participate in the same; (v) the creation of an area of mutual interest by the parties comprised of lands in the Chaveroo Field; and (vi) certain other terms and conditions standard in such participation agreements. The Participation Agreement has an initial term expiring on December 31, 2025, but continues in full force and effect for so long as the parties continue to develop the Development Blocks in accordance with the terms of the agreement. The Participation Agreement includes customary representations and warranties of the parties and also provides that any new leases acquired by the Company within certain identified tracts within two years from the date of the agreement will become Existing Leases under the agreement.
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Pursuant to the Participation Agreement, in September 2023 Evolution acquired a 50% working interest share in Existing Leases covering approximately 813 net acres located in the first and second Development Blocks in exchange for the payment of $366,000 in total proceeds to the Company, and in June 2024 Evolution acquired a 50% working interest share in Existing Leases covering approximately 811 net acres located in the third, fourth and fifth Development Blocks in exchange for the payment of $365,000 in total proceeds to the Company.
In addition, in December 2023, the Company’s operator, 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.
D-J Basin Asset
We have grown our legacy D-J Basin Asset position to approximately 14,809 net acres in Weld and Morgan Counties, Colorado and approximately 3,860 net acres in Laramie County, Wyoming. We directly hold all of our interests in the D-J Basin Asset through our wholly-owned subsidiary, PRH. These interests are all located in Weld and Morgan Counties, Colorado and Laramie County, Wyoming. PRH has an interest in 82 gross (21.9 net) wells and our wholly-owned operating subsidiary, Red Hawk, is currently the operator of 17 gross (15.4 net) wells located in our D-J Basin Asset. Our D-J Basin Asset acreage is located in the areas shown in the map below. The D-J Basin’s Wattenberg Extension has seen a tremendous amount of growth in drilling activity since 2018 due to enhanced completions design and interest in the area as a result of its remote location away from more populated areas of the Wattenberg play to the south. D-J Basin operators are drilling horizontal wells in the Niobrara formation in several Niobrara benches and in the Codell formation, utilizing the latest advances in completion design, frac stages, and frac intensity to obtain favorable well results. Notable non-operated partners leading the Niobrara revival are Chevron Corporation (which acquired Noble Energy in October 2020 and PDC Energy in August 2023), Civitas Resources, Inc. (formed by the merger of Bonanza Creek Energy and Extraction Oil and Gas in November 2021) and several large private equity-backed independent E&P companies like Bison Oil & Gas IV and Verdad Resources LLC. Other active operators in the area include Fundare Resources Company, LLC (which acquired Whiting Petroleum Company’s D-J Basin interests in late 2019), and Occidental Petroleum (which acquired Anadarko Petroleum in 2019).
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Weld and Morgan Counties, Colorado and Laramie County, Wyoming
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| Table of Contents |
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, 2024, 2023, and 2022:
|
| 2024 |
|
| 2023 |
|
| 2022 |
| |||
|
|
|
|
|
|
|
|
|
| |||
Total Revenues |
| $ | 39,553,000 |
|
| $ | 30,784,000 |
|
| $ | 30,034,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil: |
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (Bbls) |
|
| 492,396 |
|
|
| 382,794 |
|
|
| 304,507 |
|
Average sales price (per Bbl) |
| $ | 73.50 |
|
| $ | 72.95 |
|
| $ | 90.86 |
|
Natural Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (Mcf) |
|
| 608,382 |
|
|
| 479,533 |
|
|
| 245,923 |
|
Average sales price (per Mcf) |
| $ | 2.00 |
|
| $ | 3.00 |
|
| $ | 6.41 |
|
NGL: |
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (Bbls) |
|
| 78,003 |
|
|
| 58,170 |
|
|
| 19,277 |
|
Average sales price (per Bbl) |
| $ | 27.48 |
|
| $ | 24.43 |
|
| $ | 40.87 |
|
Oil Equivalents: |
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (Boe) (1) |
|
| 671,796 |
|
|
| 520,886 |
|
|
| 364,771 |
|
Average Daily Production (Boe/d) |
|
| 1,835 |
|
|
| 1,427 |
|
|
| 999 |
|
Average Production Costs (per Boe) (2) |
| $ | 10.36 |
|
| $ | 8.98 |
|
| $ | 13.12 |
|
_________________________
(1) | Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil. |
(2) | Excludes workover costs, marketing, ad valorem, severance taxes and ARO Settlements. |
As of December 31, 2024, the Wattenberg Field in our D-J Basin Asset and as of December 31, 2023 and 2022, 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, 2024, 2023, and 2022, are represented in the table below in total barrels (Bbls):
|
| 2024 |
|
| 2023 |
|
| 2022 |
| |||
Chaveroo (Permian Asset Base) |
|
| - |
|
|
| 168,458 |
|
|
| 211,310 |
|
Wattenberg (D-J Asset Base) |
|
| 333,635 |
|
|
| 331,896 |
|
|
| 91,685 |
|
The following table summarizes our gross and net developed and undeveloped leasehold acreage Iat December 31, 2024:
|
| Total |
|
| Developed (1) |
|
| Undeveloped (2) |
| |||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
D-J Basin |
|
| 82,560 |
|
|
| 18,669 |
|
|
| 69,760 |
|
|
| 11,150 |
|
|
| 12,800 |
|
|
| 7,519 |
|
Permian Basin |
|
| 26,240 |
|
|
| 14,105 |
|
|
| 21,760 |
|
|
| 13,785 |
|
|
| 4,980 |
|
|
| 320 |
|
Total |
|
| 108,800 |
|
|
| 32,774 |
|
|
| 91,520 |
|
|
| 24,935 |
|
|
| 17,280 |
|
|
| 7,839 |
|
(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, 809 net acres are set to expire during 2025 (net to our direct ownership interest only), with 3,662 and 1,657 net acres set to expire for the years ending December 31, 2026 and 2027 respectively, and 508.53 net acres thereafter; and (ii) in the Permian Basin Asset only 200 net acres are set to expire for the year ending December 31, 2026, (net to our direct ownership interest only), with all of the remaining acreage currently held by production. We expect to retain substantially all of our expiring acreage either through drilling activities, renewal of the expiring leases or through the exercise of extension options.
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Well Summary
The following table presents our ownership in productive crude oil and natural gas wells at December 31, 2024. This summary includes crude oil wells in which we have a working interest:
|
| Gross |
|
| Net |
| ||
Crude oil |
|
| 117.0 |
|
|
| 59.3 |
|
Natural gas |
|
| - |
|
|
| - |
|
Total* |
|
| 117.0 |
|
|
| 59.3 |
|
* Total percentage of gross operated wells is 47.0%.
Drilling Activity
We drilled wells or participated in the drilling of wells as indicated in the table below:
|
| 2024 |
|
| 2023 |
|
| 2022 |
| |||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Development |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Productive |
|
| 27 |
|
|
| 5.1 |
|
|
| 8 |
|
|
| 0.4 |
|
|
| 8 |
|
|
| 4.1 |
|
Dry |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
Exploratory |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
Dry |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
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, 2024, the Company’s total estimated proved reserves were 18.1 million Boe, of which 14.2 million Bbls were crude oil and NGL reserves, and 23.4 million Mcf were natural gas reserves.
Internal Controls. Arvind Krishna, our Director of Development and Reservoir Engineering (a non-executive position), is the technical person primarily responsible for our internal reserves estimation process (which is based upon the best available production, engineering and geologic data) and has in excess of five years as a reserves estimator and provides oversight of the annual audit of our year end reserves by our independent third party engineers. He has a Master of Science degree in Petroleum Engineering from The University of Texas at Austin and an MBA from Rice University.
The preparation of our reserve estimates is in accordance with our prescribed procedures that include verification of input data into reserve forecasting and economic software, as well as management review. Our reserve analysis includes, but is not limited to, the following:
| · | Research of operators near our lease acreage. Review operating and technological techniques, as well as reserve projections of such wells. |
| · | The review of internal reserve estimates by well and by area by a qualified petroleum engineer. A variance by well to the previous year-end reserve report is used as a tool in this process. |
| · | SEC-compliant internal policies to determine and report proved reserves. |
| · | The discussion of any material reserve variances among management to ensure the best estimate of remaining reserves. |
Qualifications of Third-Party Engineers. The technical person primarily responsible for the audit of our reserves estimates at Cawley, Gillespie & Associates, Inc. is W. Todd Brooker, who meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Cawley, Gillespie & Associates, Inc. is an independent firm and does not own an interest in our properties and is not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. A copy of the report issued by Cawley, Gillespie & Associates, Inc. is attached to this Report as Exhibit 99.1.
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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
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 approximately 16,900 gross acre Area of Mutual Interest wherein the Joint Development Party will transfer 30% of future interests acquired by the Joint Development Party in leaseholds to PRH, and PRH will transfer 70% of future interests acquired by PRH in leaseholds to the Joint Development Party, in each case at an acquisition cost proportionate to their respective interests. The assigned interests will be subject to an overriding royalty, such that the assigning party shall deliver to the other party leasehold interests with an 80% net revenue interest, and the parties agreed that the Joint Development Party will be the operator of the combined leaseholds. The Participation Agreement specifically addresses the Harlequin Wells, which are existing wells within the SW Pony Prospect, whereby PRH acquired a 30% undivided interest in six Harlequin Wells as part of the leasehold assignment. The Company correspondingly paid $8.6 million in capital costs related to these wells.
In February 2025, the Company entered into a joint development agreement (“Agreement”) with a large, Denver, Colorado-based private equity-backed D-J Basin E&P Company with extensive operational experience (“Operator”), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company’s Roth and Amber 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.
Sale of Non-Core D-J Basin Assets
On September 23, 2024, PRH sold 320 net acres to a third-party in the Company’s D-J Basin Asset for $750,000, and, with the Company recognizing a $735,000 gain from the sale of oil and gas properties.
Drilling and Completion, Leasing, and Mineral Lease Acquisition Activities
For the year ended December 31, 2024, the Company incurred $20.5 million of capital costs. These costs were primarily related to non-operated drilling and completion costs related to the Company’s participation in 24 new non-operated wells in the D-J Basin in which the Company participated and the Company’s completion operations with respect to three operated wells with a third-party in the Permian Basin, together with costs related to certain workovers for lift conversions, cleanouts and permitting in the Company’s D-J Basin Asset.
The Company also acquired approximately 267 net mineral acres and 4,960 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 $725,000 and $862,000, respectively.
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Reserve-Based Lending Facility
On September 11, 2024, the Company entered into a new $250 million reserve-based lending facility (the “RBL” or “Facility”) with Citibank, N.A., as administrative agent, and the lenders (including Citibank, N.A.) from time to time a party thereto. The Facility has a maturity of four years and provides for an initial borrowing base of $20.0 million and an aggregate maximum revolving credit amount of $250 million. The Company has not drawn down any borrowings under the Facility as of the date of these financial statements. The RBL includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Loan Parties from creating any indebtedness without the consent of the lenders, subject to certain exceptions, and requiring the Company to have a net leverage ratio (the ratio of (a) total net debt to (b) EBITDAX) of no less than 1.0 to 1.0 and a current ratio (the ratio of (i) consolidated current assets to (ii) consolidated current liabilities) of no less than 1.0 to 1.0. EBITDAX is defined as Earnings Before Interest, Taxes, Depreciation (or Depletion), Amortization, and Exploration Expense.
Milnesand Sale Dispute and Tilloo Note Default
On November 4, 2024 the Company received correspondence from legal counsel to Tilloo Exploration & Production, LLC (“Tilloo”) seeking to recover damages which Tilloo is alleging were caused by alleged intentional misrepresentations made by principals of the Company to principals of Tilloo in connection with Tilloo’s acquisition of the Milnesand and Sawyer fields in New Mexico from the Company for aggregate consideration of $1,122,436 effective August 1, 2023 (the “Milnesand Sale”), which consideration was paid to the Company by Tilloo via a five-year secured promissory note with 10% annual interest and no payments due until January 8, 2025 (the “Tilloo Note”). The Company does not believe any misrepresentations were made by the Company or its principals in the Milnesand Sale and that the claims are baseless, without merit, and fail as a matter of law. The Company has not received any correspondence from Tilloo subsequent to receipt of the November 4, 2024 correspondence from Tilloo, and Tilloo failed to make the initial installment payment due under the Tilloo Note on January 8, 2025. The Company issued a notice of default under the Tilloo Note to Tilloo in mid-January 2025, and the Company intends to pursue all available avenues and remedies, including potential foreclosure under the security agreement and mortgages securing the secured obligation, to resolve these matters.
Regulation of the Oil and Gas Industry
All of our oil and gas operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future costs or impact of compliance.
Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (the “FERC”) and the courts, and, in Colorado, the county level. We cannot predict when or whether any such proposals may become effective, and it is difficult to estimate the potential impact on our business from rules and regulations adopted by the federal government and states in which we operate. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
At the state level, our operations in Colorado are regulated by the Energy & Carbon Management Commission (“ECMC”) (formerly the Colorado Oil & Gas Conservation Commission (“COGCC”)), our planned operations in Wyoming will be 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.
Regulation Affecting Production
The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and gas wells we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction.
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States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.
The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. State laws also may prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our leases. Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation Affecting Sales and Transportation of Commodities
Sales prices of gas, oil, condensate and NGL are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting requirements.
The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of oil and natural gas produced by the Company, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.
The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.
In addition to the regulation of natural gas pipeline transportation, the FERC has additional jurisdiction over the purchase or sale of gas or the purchase or sale of transportation services subject to the FERC’s jurisdiction pursuant to the Energy Policy Act of 2005 (“EPAct 2005”). Under the EPAct 2005, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the Natural Gas Act of 1938 (“NGA”) to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act of 1978 up to $1.5 million per day, per violation. The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No. 704 (defined below).
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In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, any market participant, including a producer that engages in certain wholesale sales or purchases of gas that equal or exceed 2.2 trillion BTUs of physical natural gas in the previous calendar year, must annually report such sales and purchases to the FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to the formation of price indices. Not all types of natural gas sales are required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation. We are not currently subject to the requirement to report on Form No. 552, as our sales of oil and natural gas do not rise to the minimum level required for reporting by Order No. 704.
The FERC also regulates rates and terms and conditions of service on interstate transportation of liquids, including oil and NGL, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that certain interstate liquids pipelines maintain a tariff on file with the FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Increases in liquids transportation rates may result in lower revenue and cash flows for the Company. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.
In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.
In addition to the FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1.3 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to oil purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1.1 million or triple the monetary gain to the person for each violation.
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Environmental and Occupational Safety and Health Matters
Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Continued compliance with existing requirements is not expected to materially affect us. However, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.
The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Air Emissions
Our operations are subject to the Clean Air Act (the “CAA”) and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to make certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.
Federal Air Regulation
The EPA adopted regulations requiring the reporting of GHG emissions from specific categories of higher GHG emitting sources in the U.S., including certain crude oil and natural gas production facilities, which include certain of our operations. Information in such reporting may form the basis for further GHG regulation. Further, the EPA has continued with its comprehensive strategy for further reducing methane emissions from oil and gas operations, with a final rule being issued in June 2016 as part of the Subpart OOOOa NSPS. In November 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA announced a final rule in December 2023, which, among other things, requires the phase out of routine flaring of natural gas from new crude oil wells and routine leak monitoring at all well sites and compressor stations. Notably, EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources until March 2026. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply. The final rule is subject to ongoing litigation but remains in effect. More recently, the EPA finalized on March 8, 2024, additional final NSPS OOOO program final rules—referred to as Subparts OOOOb and OOOOc—which, became effective May 7, 2024, and are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective. The rules impose additional methane and VOC emissions limitations from new, modified, and reconstructed sources, and will regulate existing sources for the first time under the NSPS OOOOc program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of VOC and methane emissions for the oil and gas production, transmission, and storage industry segments are uncertain at this time and could be modified further as a result of ongoing rulemakings and expected legal challenges. The EPA’s GHG rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. 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. Consequently, future implementation and enforcement of the final rule remains uncertain at this time.
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More recently, the EPA finalized on March 8, 2024, additional final NSPS OOOO program final rules—referred to as Subparts OOOOb and OOOOc—which, became effective May 7, 2024, and are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective. The rules impose additional methane and VOC emissions limitations from new, modified, and reconstructed sources, and will regulate existing sources for the first time under the NSPS OOOOc program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of VOC and methane emissions for the oil and gas production, transmission, and storage industry segments are uncertain at this time and could be modified further as a result of ongoing rulemakings and expected legal challenges. Changes in the U.S. presidential administration following the 2024 presidential election could also affect the implementation of the NSPS Subpart OOOOb and OOOOc rules.
In October 2015, the EPA finalized its rule lowering the earlier 75 part per billion (“ppb”) national ambient air quality standards (“2008 NAAQS”) for ozone under the CAA to 70 ppb (“2015 NAAQS”). The state of Colorado’s Denver Metro and North Front Range (“DM/NFR”) air quality control region has been unable to attain the 2008 and 2015 ozone NAAQS since their adoption, and its existing non-attainment status for the 2008 NAAQS was reclassified from “serious” to “severe” in 2022 due to violations at area monitors during the 2020 ozone season. A “severe” classification triggers significant additional obligations under the CAA and state laws and will result in new and more stringent air quality control requirements applicable to our operations in Colorado and significant operating costs and delays in obtaining necessary permits for new and modified production facilities. Among other requirements, a “severe” classification for the 2008 NAAQS may require additional permitting in the nonattainment area for any source with the potential to emit more than 25 tons per year of volatile organic compounds or nitrogen oxides. Additionally, the DM/NFR’s non-attainment boundary for the 2015 NAAQS was successfully challenged by environmental groups and local governments seeking to expand the boundary to include all of northern Weld County in the case of Clean Wisconsin v. EPA, No. 18-1203, in which the D.C. Circuit Court remanded the boundary determination to the EPA for further support or re-designation. In response, the EPA chose to re-designate the boundary for the 2015 ozone NAAQS to include all of Weld County, which action became effective on December 30, 2021. Weld County challenged the EPA’s action upon remand in the D.C. Circuit, and the D.C. Circuit Court denied Weld County’s petition for review in June 2023. Bd. of County Comm. of Weld County v. EPA, No. 21-1263. While the Permian Basin in New Mexico has not been designated as being in nonattainment with federal ozone standards, the EPA’s 2023 proposal to designate the Permian Basin as being in nonattainment remains pending.
In November 2022, the Bureau of Land Management (“BLM”) published a proposed rule that would regulate venting, flaring and leaks during oil and gas production activities on federal and Indian leases. If finalized as proposed, the rule would limit gas that may be flared royalty-free during well completions, production testing, and emergencies; establish a monthly volume limit on royalty-free flaring due to pipeline capacity constraints, midstream processing failures, or other similar events; require vapor recovery systems on oil tanks; require operators to maintain leak detection and repair (“LDAR”) programs; prohibit the use of certain natural-gas-activated pneumatic controllers and pneumatic diaphragm pumps; and require operators to submit waste minimization plans with applications for permit to drill, among other requirements.
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State Air Regulation
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 denied the petition; however, the COGCC 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.
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Compliance with these and other air pollution control, air monitoring, gas capture, and permitting requirements has the potential to delay the development of crude oil and natural gas projects and increase our costs of development and production, which costs could be significant.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process.
The federal Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment, or release of water produced or used during oil and gas development. Subsurface emplacement of fluids, primarily via disposal wells or enhanced oil recovery wells (“EOR Wells”), is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory or the state’s environmental authority. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for EOR Wells is not excluded.
Federal agencies have periodically considered additional regulation of hydraulic fracturing. The EPA has published guidance for issuing underground injection permits that would regulate hydraulic fracturing using diesel fuel. This guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing. In June 2016, the EPA finalized regulations that address discharges of wastewater pollutants from onshore unconventional extraction facilities to publicly-owned treatment works. The EPA also published a study of the impact of hydraulic fracturing on drinking water resources, which concluded that drinking water resources can be affected by hydraulic fracturing under specific circumstances. The results of this study could result in additional regulations, which could lead to operational burdens similar to those described above; however, the EPA has taken no further action in response to the study to date. In April 2024, the BLM finalized a rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and Indian leases, which became effective in June 2024. However, numerous states challenged the rule, and litigation is ongoing in the District of North Dakota, which granted a preliminary injunction enjoining BLM from enforcing the rule in the plaintiff states in September 2024. 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. As a result, future implementation and enforcement of this rule remains uncertain at this time.
In addition, oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“NEPA”). The NEPA 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 assesses 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. Authorizations under the NEPA also are subject to protest, appeal, or litigation, which can delay or halt projects. In July 2020, the Council on Environmental Quality (“CEQ”) revised the NEPA’s implementing regulations to make the NEPA process more efficient, effective, and timely. The rule required federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date (which was extended to two years in June 2021). These regulations are subject to ongoing litigation in several federal district courts, and in October 2021, CEQ issued a notice of proposed rulemaking to amend the NEPA regulatory changes adopted in 2020 in two phases. Phase I of the CEQ’s proposed rulemaking process was finalized in April 2022, and generally restored provisions that were in effect prior to 2020. In July 2023, CEQ issued a proposed rule for the Phase II rulemaking. The proposed Phase II rule restores certain mitigation language from the pre-2020 version of the NEPA regulations, proposes further revisions to ensure the NEPA process “provides for efficient and effective environmental reviews,” and meets environmental, environmental justice, and climate change objectives. The final rule was made effective May 1, 2024. However, at least twenty states challenged the Phase II rule in federal district court. In addition, in January 2025, President Trump issued executive orders directing (i) CEQ to provide guidance on implementing NEPA and to propose rescinding and replacing CEQ’s NEPA regulations with implementing regulations at the agency level and (ii) 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. In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our business and operations.
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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, which injunction is being appealed. President Biden resumed 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 4% of the Company’s acreage in Wyoming is located on federal lands. It is currently unclear whether future moratoriums will be imposed, if any, and whether such actions herald the start of a change in federal policies regarding the grant of oil and gas permits on federal lands.
Apart from these ongoing federal and state initiatives, some state and local governments where we operate have adopted their own new requirements on hydraulic fracturing and other oil and gas operations and, in some cases, have proposed initiatives restricting or banning oil and gas development altogether. For example, Colorado Senate Bill 19-181 amended state law to give municipalities and counties greater local control over siting and permitting of oil and gas locations, and some municipalities within the state have implemented regulations within their jurisdictions. Any successful bans or moratoria where we operate, whether at the state or local level, could increase the costs of our operations, impact our profitability, and even prevent us from drilling in certain locations which could adversely impact our ability to develop our reserves. In addition, in light of concerns about seismic activity potentially being triggered by the injection of produced waters into underground wells, regulators in the states in which we operate have adopted additional requirements related to seismic safety for hydraulic fracturing activities or the underground injection of fluid wastes. For example, the regulations that the ECMC adopted in November 2020 impose various requirements on the underground injection of fluid wastes to further seismic safety and protect the environment. In New Mexico, the New Mexico Oil Conservation Division (“OCD”) implemented a Seismicity Response Protocol that is implemented either through voluntary actions by operators and/or orders issued by the OCD in response to increased seismic activity believed to be related to injection wells throughout New Mexico. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could have a material adverse effect on our business.
At this time, it is not possible to estimate the potential impact on our business of recent state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. The adoption of future federal, state, or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete crude oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products. The outcome of such legislation or regulation may have a material and adverse impact on our cash flows and results of operations.
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.
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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 (“SFO”) 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.
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Moreover, because most of our operations are conducted in two particular areas, the Permian Basin in New Mexico and the D-J Basin in Colorado, and potentially extending into Wyoming in the future, 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 Permian Basin in New Mexico and/or the D-J Basin in Colorado and/or Wyoming 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.
Water Discharges
The Federal Clean Water Act (“CWA”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable and other regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “USACE”). Whether CWA permitting is required depends upon whether and the extent to which “Waters of the United States” (“WOTUS”) may be impacted by the planned activity—for example, construction of drilling pads, access roads, or pipelines. Rulemaking by EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states. The EPA’s and USACE’s WOTUS definition rulemaking published in the Federal Register on January 18, 2023 (the “January 2023 Rule”) incorporated “relatively permanent” and “significant nexus” standards for determining jurisdiction over adjacent wetlands and additional waters, thereby expanding the types of waters that could be considered WOTUS. However, this WOTUS definition was litigated and eventually amended on August 29, 2023, when the EPA and USACE issued a final rule to conform the WOTUS definition to the U.S. Supreme Court’s May 25, 2023, decision in Sackett v. Environmental Protection Agency, which invalidated parts of the January 2023 Rule. With the August 2023 rulemaking, the EPA and USACE implemented a narrower definition of WOTUS by, for example, removing “interstate wetlands”; redefining “adjacent” to mean “having a continuous surface connection”; and removing the “significant nexus” standard from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds. To the extent any litigation or future amendments to the rule expand the scope of the Clean Water Act’s jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or in connection with stream crossings and preparation and implementation of oil spill prevention, control, and countermeasure (“SPCC”) plans.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. In addition, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses a substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect the Company’s operations.
SPCC regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 require operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, to develop, implement, and maintain an SPCC plan. The SPCC plan must describe oil handling operations, spill prevention practices, discharge or drainage controls, and the personnel, equipment and resources at the facility that are used to prevent oil spills from reaching navigable and other regulated waters or adjoining shorelines, and reviewed at least every five years.
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Pursuant to CWA laws and regulations, the Company may also be required to obtain and maintain approvals or permits for the discharge of wastewater, including produced water, or storm water. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal, remediation and damages.
Hazardous Substances and Wastes
The Federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under the RCRA and, instead, are regulated under the RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Stricter regulation of wastes generated during our operations could result in an increase in our, as well as the oil and natural gas exploration and production industry’s costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.
We currently lease or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
Subsurface Injections
In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal SDWA and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near belowground disposal wells used for the injection of oil and natural gas-related wastewaters, regulators in some states, including Colorado, have imposed more stringent permitting and operating requirements for produced water disposal wells. In Colorado, permit applications are reviewed specifically to evaluate seismic activity and, since 2011, the state has required operators to identify potential faults near proposed wells, if earthquakes historically occurred in the area, and to accept maximum injection pressures and volumes based on fracture gradient as conditions to permit approval. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, and increased costs of compliance, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.
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In addition, the U.S. Supreme Court’s April 2020 ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs for the Company if permits are required under the CWA for disposal of the Company’s flowback and produced water in disposal wells, In November 2023, the EPA issued draft guidance outlining the factors that may be considered when evaluating whether discharges through groundwater may be the “functional equivalent” of a direct discharge, and thereby subject to regulation under the CWA National Pollutant Discharge Elimination System Permit Program (which permits point sources to discharge specified amounts of pollutant(s) to waters of the United States under specified conditions, and describes the types of information that should be used in determination). The EPA held a comment period for the draft guidance in November and December 2023, but to date the EPA has not finalized any guidance, with the next steps for this guidance unclear given the January 2025 presidential transition.
Our properties located in New Mexico are subject to the authority of the New Mexico Environment Department and the Energy, Minerals and Natural Resources Department’s OCD, as well as other state agencies. In December 2023, the New Mexico Environment Department proposed new regulations that would require the reuse of produced water generated by the oil and gas industry, so long as there is no discharge to surface or groundwater. Public hearings commenced May 13, 2024, and a final rule is expected in 2025.
Regulation of Flowlines
Pipelines, gathering systems, and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation and storage of refined products and crude oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant penalties, liability for natural resources damages, and significant business interruption. The U.S. Department of Transportation has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection, and management of our pipeline and storage facilities. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.
There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. The Pipeline Safety, Regulatory Certainty, and Job Creation Act was signed into law in early 2012. In addition, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has issued new rules to strengthen federal pipeline safety enforcement programs. In 2015, the PHMSA proposed to expand its regulations in a number of ways, including through the increased regulation of gathering lines, even in rural areas. In 2016, the PHMSA increased its regulations to require crude oil sampling and reporting as an “offeror” (as defined under the PHMSA) and increased its civil penalty structure. In November 2021, the PHMSA issued its final rule extending reporting requirements to all onshore gas gathering operators and applying a set of minimum safety requirements to certain onshore gas gathering pipelines with large diameters and high operating pressures.
In Colorado, on March 17, 2021, the Public Utilities Commission adopted Regulation 11 rules Regulating Pipeline Operators and Gas Pipeline Safety. These regulations apply to all gas public utilities, all municipal or quasi-municipal corporations transporting natural gas or providing natural gas services, all operators of master meter systems, and all operators of pipelines transporting gas in intrastate commerce including gas gathering system operators (certain provisions are tailored to the location and size of the gathering systems involved). The rules require all filed reports to be publicly available and all Notices of Proposed Violation, Notices of Action, pleadings and decisions to be filed publicly. The rules also provide a revised methodology for calculating civil penalties in an effort to provide clarity to both operators and the public.
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Global Warming and Climate Change
The EPA has published findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources.
In August 2022, then President Biden signed into law the Inflation Reduction Act of 2022. Among other things, the Inflation Reduction Act includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain oil and gas sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. Among other things, the new rule expands the emissions events that are subject to reporting requirements to include “other large release events” and applies reporting requirements to certain new sources and sectors. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program. However, petitions for reconsideration to EPA are pending and litigation in the D.C. Circuit has commenced. In November 2024, EPA finalized a rule to implement the Inflation Reduction Act’s Waste Emissions Charge. The fee imposed under the Methane Emissions and Waste Reduction Incentive 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. The emissions fee and funding provisions of the Inflation Reduction Act could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. However, in January 2025, President Trump issued executive orders directing an immediate pause on the disbursement of funds appropriated through the Inflation Reduction Act, and also directed withdrew the United States from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. Consequently, future implementation and enforcement of these rules remains uncertain at this time.
In addition, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies, and incentives to encourage the use of renewable energy or alternative low-carbon fuels, the development of greenhouse gas inventories, and cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.
Additionally, on March 6, 2024, the SEC issued its final rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors, which requires large accelerated and accelerated filers to provide climate-related disclosures in their annual reports and registration statements beginning with annual reports for the year ending December 31, 2025 for calendar-year-end filers, and beginning with annual reports for the year ending December 31, 2027 for smaller reporting companies like ours. The final rule requires large accelerated and accelerated filers to provide Scope 1 and Scope 2 GHG emissions disclosures and more extensive GHG-related financial statement disclosure requirements. The most stringent disclosure and reporting provisions under the SEC’s final rule do not apply to the Company as it is a smaller reporting company, but should the Company become an accelerated filer, or should future SEC rules be issued that apply such disclosure requirements on smaller reporting companies, such rules could impose significant disclosure requirements and costs on our operations. The SEC’s Greenhouse Gas Rule is currently being challenged in litigation consolidated in the Eighth Circuit, and the SEC has stayed the effective date pending completion of that litigation. Additionally, then SEC Acting Chair Mark Uyeda, on February 11, 2025, issued a statement saying the Greenhouse Gas Rule is flawed and directed the SEC staff to notify the Court of the changed circumstances and request that the Court not schedule the case for argument to provide time for the SEC to deliberate and determine the appropriate next steps in the case. At this time the final outcome of the SEC’s Greenhouse Gas Rule is unknown.
In addition, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies, and incentives to encourage the use of renewable energy or alternative low-carbon fuels, the development of greenhouse gas inventories, and cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. We do not anticipate that such fees will have material effect on our financial condition or results of operations. Congress may adopt additional significant legislation in the future to reduce emissions of GHGs.
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In May 2019, Colorado passed GHG inventory legislation and climate action legislation. House Bill 19-1261 concerns the reduction of GHG pollution and established statewide GHG pollution reduction goals. Senate Bill 19-096 concerns the collection of GHG emissions data to facilitate measures to cost-effectively meet the state’s GHG emissions reduction goals established in HB 19-1261. Regulations implementing the GHG inventory requirements of these statutes took effect on July 15, 2020. Additionally, in January 2021, the Colorado Energy Office and Colorado Department of Public Health and Environment finalized a Greenhouse Gas Pollution Reduction Roadmap. The GHG Roadmap lays out a pathway to meet the state’s climate action targets established in HB 19-1261, as amended by HB 21-1266. In October 2023, the AQCC adopted the Greenhouse Gas Emissions and Energy Management for Manufacturing Phase 2 (“GEMM 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. The final rule is expected following a review of GEMM 2 by the end of 2025.
In New Mexico, as discussed above, the NMOCD has enacted methane capture rules and additional rules regulating the monitoring of emission rates, performance of enhanced checks for leaks, repair of leaks, and maintenance of records to demonstrate continuous compliance.
Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations.
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.
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Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.
We are not able to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing, but the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our business, financial conditions and results of operations. See further discussion in “Part I” – “Item 1A. Risk Factors.”
Insurance
Our oil and gas properties are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, implosions, fires and oil spills. These conditions can cause:
| · | damage to or destruction of property, equipment and the environment; |
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| · | personal injury or loss of life; and |
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| · | suspension of operations. |
We maintain insurance coverage that we believe to be customary in the industry against these types of hazards. However, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.
Human Capital Resources
At December 31, 2024, we employed 14 people and also utilize the services of independent contractors to perform various field and other services. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.
The development, attraction and retention of employees is a critical success factor for the Company. To support the advancement and education of our employees, we offer training and development programs to our employees, including training on compliance, general business, management, harassment prevention, leadership, and workplace safety-related topics to further their personal and professional development. We also require annual anti-harassment training of all employees and supervisors.
We also offer our employees competitive pay and benefits. The Company’s compensation programs are designed to align the compensation of our employees with the Company’s performance and to provide the proper incentives to attract, retain and motivate employees to achieve superior results. The structure of our compensation programs balances incentive earnings for both short-term and long-term performance. Specifically:
| · | We provide employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. |
| · | Annual increases and incentive compensation are based on merit, which is communicated to employees at the time of hiring and documented through our annual review procedures and upon internal transfer and/or promotion. |
| · | All employees are eligible for health insurance, paid and unpaid leaves, a retirement plan and life and disability/accident coverage. We also offer a variety of voluntary benefits that allow employees to select the options that meet their needs, including flexible spending accounts, flexible time-off, telemedicine, wellness resources, legal resources and identity protection plans, family leave, and adoption assistance, among others. |
Available Information
The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Exchange Act. Such reports and other information filed by the Company with the SEC are available free of charge at https://www.pedevco.com/sec-filings when such reports are available on the SEC’s website. The Company periodically provides other information for investors on its corporate website, www.pedevco.com. This includes press releases and other information. The information contained on the websites referenced in this Annual Report is not incorporated by reference into this filing. Further, the Company’s references to website URLs are intended to be inactive textual references only.
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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:
· | The future price of oil, natural gas and NGL; |
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· | The impact of public health crises, similar to COVID-19, on the Company’s operations, future prospects, the value of its properties, and the economy in general, including the related effect on the supply and demand, and ultimate price of oil and natural gas; |
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· | Current and future declines in economic activity and recessions, changes in inflation and interest rates, and their effect on the Company, its property, prospects and the supply and demand, and ultimate price of oil and natural gas; |
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· | The status and availability of oil and natural gas gathering, transportation, and storage facilities owned and operated by third parties; |
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· | 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 may adversely affect our business, financial condition, and results of operations; |
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· | New or amended environmental legislation or regulatory initiatives which could result in increased costs, additional operating restrictions, or delays, or have other adverse effects on us; |
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· | The effect of future shut-ins of our operated production, should market conditions significantly deteriorate; |
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· | Declines in the value of our crude oil, natural gas and NGL properties resulting in impairments; |
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· | Our need for additional capital to complete future acquisitions, conduct our operations and fund our business, and our ability to obtain such necessary funding on favorable terms, if at all; |
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· | Our ability to generate sufficient cash flow to meet any future debt service and other obligations due to events beyond our control; |
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· | The fact that all of our assets and operations are located in the Permian Basin and the D-J Basin, making us vulnerable to risks associated with operating in only two geographic areas; |
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· | The speculative nature of our oil and gas operations, and general risks associated with the exploration for, and production of oil and gas; including accidents, equipment failures or mechanical problems which may occur while drilling or completing wells or in production activities; operational hazards and unforeseen interruptions for which we may not be adequately insured; the threat and impact of terrorist attacks, cyber-attacks or similar hostilities; declining reserves and production; and losses or costs we may incur as a result of title deficiencies or environmental issues in the properties in which we invest, any one of which may adversely impact our operations; |
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· | Potential conflicts of interest that could arise for certain members of our management team and Board of Directors that hold management positions with other entities and our largest stockholder; |
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· | The limited control we have over activities on properties we do not operate; |
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· | The estimates of the value of our oil and gas properties and accounting in connection therewith; |
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· | Intense competition in the oil and natural gas industry; |
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· | Our competitors use of superior technology and data resources that we may be unable to afford or obtain the use of; |
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· | Changes in the legal and regulatory environment governing the oil and natural gas industry, including new or amended environmental legislation or regulatory initiatives which could result in increased costs, additional operating restrictions, or delays, or have other adverse effects on us; |
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· | Uncertainties associated with enhanced recovery methods which may result in us not realizing an acceptable return on our investments in such projects or suffering losses; |
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· | Requirements that we must drill on certain of acreage in order to hold such acreage by production; |
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· | Improvements in or new discoveries of alternative energy technologies that could have a material adverse effect on our financial condition and results of operations; |
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· | Future litigation or governmental proceedings which could result in material adverse consequences, including judgments or settlements; |
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· | The currently sporadic and volatile market for our common stock; |
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· | Our dependence on the continued involvement of our present management; |
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· | The fact that Dr. Simon G. Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, beneficially owns a majority of our common stock and that his interests may be different from other shareholders; |
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· | Our ability to maintain the listing of our common stock on the NYSE American; |
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· | Dilution caused by future offerings; |
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· | Future material impairments of our oil and gas assets; and |
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· | Other risks described under “Risk Factors” below. |
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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 60% of our estimated proved reserves as of December 31, 2024 were oil, our financial results are more sensitive to movements in oil prices. The price of crude oil has experienced significant volatility over the last five years, with the price per barrel of West Texas Intermediate (“WTI”) crude, dropping below $20 per barrel in 2020 due in part to reduced global demand stemming from the global COVID-19 outbreak, and surging to over $120 a barrel in early March 2022, following Russia’s invasion of the Ukraine, to the $70s in recent months. 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:
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| Daily NYMEX WTI oil spot price (per Bbl) |
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| Daily NYMEX natural gas Henry Hub spot price (per MMBtu) |
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| High |
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| Low |
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| High |
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| Low |
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Year ended December 31, 2020 |
| $ | 63.27 |
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| $ | (36.98 | ) |
| $ | 3.14 |
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| $ | 1.33 |
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Year ended December 31, 2021 |
| $ | 85.64 |
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| $ | 47.47 |
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| $ | 23.86 |
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| $ | 2.43 |
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Year ended December 31, 2022 |
| $ | 123.64 |
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| $ | 71.05 |
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| $ | 9.85 |
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| $ | 3.46 |
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Year ended December 31, 2023 |
| $ | 93.67 |
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| $ | 66.61 |
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| $ | 3.78 |
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| $ | 1.74 |
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Year ended December 31, 2024 |
| $ | 87.69 |
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| $ | 66.73 |
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| $ | 13.20 |
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| $ | 1.21 |
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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 $106,002,000 from the date of inception (February 9, 2011) through December 31, 2024. 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, conduct our operations and fund our business beyond 2025, and our ability to obtain the necessary funding is uncertain.
We may need to raise additional funding to complete future potential acquisitions and may be required to raise additional funds through public or private debt or equity financing or other various means to fund our operations and complete exploration and drilling operations beyond 2025 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. 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.
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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 concluded that certain of our previously issued financial statements should not be relied upon and have restated certain of our previously issued financial statements which may affect investor confidence and raise reputational issues and may subject us to additional risks and uncertainties, including increased professional costs and the increased possibility of legal proceedings and regulatory inquiries.
As discussed in Note 4 to our audited consolidated financial statements included under Restatement of Previously Issued Consolidated Financial Statements, we determined to restate our consolidated financial statements as of December 31, 2023 and 2022, respectively, after we identified errors in our calculation of depletion expenses for our oil and gas properties. As a result of this error and the resulting restatement of our consolidated financial statements for the impacted periods, we have incurred, and may continue to incur, unanticipated costs for accounting and legal fees in connection with or related to the restatement, and have become subject to a number of additional risks and uncertainties, including the increased possibility of litigation and regulatory inquiries. Any of the foregoing may affect investor confidence in the accuracy of our financial disclosures and may raise reputational risks for our business, both of which could harm our business and financial results.
Our industry and the broader US economy have experienced higher than expected inflationary pressures in 2022, related to continued supply chain disruptions, labor shortages and geopolitical instability. Should these conditions persist our business, results of operations and cash flows could be materially and adversely affected.
Year 2022 saw significant increases in the costs of certain services and materials, including steel, sand and fuel, as a result of availability constraints, supply chain disruption, increased demand, labor shortages associated with a fully employed US labor force, high inflation, interest rates and other factors, with supply and demand fundamentals being further aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing conflict between Russia and Ukraine and the current armed conflict in Israel and the Gaza Strip, all resulting in an estimated cost increase of approximately 25% to 30% per well on our Permian Asset and 10% to 20% on our D-J Basin Asset, based on costs we experienced commencing in the third quarter of 2021 and continuing throughout 2022. Service and materials costs also increased accordingly through 2022, stabilizing in 2023 in 2024, with general supply chain and inflation issues seen throughout the industry leading to increased operating costs. While the Company is cautiously optimistic that such costs have plateaued and will hold at current levels as we have not seen significant cost increases in 2024 and thus far in 2025, supply chain constraints, the effect of tariffs, and inflationary pressures may adversely impact our operating costs and may negatively impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
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 ongoing conflict between the Ukraine and Russia and the current armed conflict in Israel and the Gaza Strip, 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.
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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, 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 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.
We may not be able to generate sufficient cash flow to meet any future debt service and other obligations due to events beyond our control.
Our ability to generate cash flows from operations, to make payments on or refinance potential future indebtedness and to fund working capital needs and planned capital expenditures will depend on our future financial performance and our ability to generate cash in the future. Our future financial performance will be affected by a range of economic, financial, competitive, business and other factors that we cannot control, such as general economic, legislative, regulatory and financial conditions in our industry, the economy generally, the price of oil and other risks described below. A significant reduction in operating cash flows resulting from changes in economic, legislative or regulatory conditions, increased competition or other events beyond our control could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service future potential debt and other obligations. If we are unable to service future potential indebtedness or to fund our other liquidity needs, we may be forced to adopt an alternative strategy that may include actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing such indebtedness, seeking additional capital, or any combination of the foregoing. If we raise debt, it would increase our interest expense, leverage and our operating and financial costs. We cannot assure you that any of these alternative strategies could be affected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on future potential indebtedness or to fund our other liquidity needs. Reducing or delaying capital expenditures or selling assets could delay future cash flows. In addition, the terms of future debt agreements may restrict us from adopting any of these alternatives. We cannot assure you that our business will generate sufficient cash flows from operations or that future borrowings will be available in an amount sufficient to enable us to pay such future potential indebtedness or to fund our other liquidity needs.
If for any reason we are unable to meet our future potential debt service and repayment obligations, we may be in default under the terms of the agreements governing such indebtedness, which could allow our creditors at that time to declare such outstanding indebtedness to be due and payable. Under these circumstances, our lenders could compel us to apply all of our available cash to repay our borrowings. In addition, the lenders under our credit facilities or other secured indebtedness could seek to foreclose on any of our assets that are their collateral. If the amounts outstanding under such indebtedness were to be accelerated, or were the subject of foreclosure actions, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders.
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All of our crude oil, natural gas and NGLs production is located in the Permian Basin and the D-J Basin, making us vulnerable to risks associated with operating in only two geographic areas. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.
Our current operations are focused solely in the Permian Basin located in Chaves and Roosevelt Counties, New Mexico, and the D-J Basin of Weld and Morgan Counties, Colorado, with potential future operations extending into Laramie County, Wyoming, which means our current producing properties and new drilling opportunities are geographically concentrated in those two 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:
| · | fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in these areas; |
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| · | natural disasters such as the flooding that occurred in the D-J Basin area in September 2013; |
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| · | the effects of local quarantines; |
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| · | restrictive governmental regulations; and |
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| · | curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells. |
For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Permian 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 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.
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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:
| · | general economic and industry conditions, including the prices received for oil and natural gas; |
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| · | shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; |
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| · | potential significant water production which could make a producing well uneconomic, particularly in the Permian Basin Asset, where abundant water production is a known risk; |
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| · | potential drainage by operators on adjacent properties; |
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| · | loss of, or damage to, oilfield development and service tools; |
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| · | problems with title to the underlying properties; |
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| · | increases in severance taxes; |
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| · | adverse weather conditions that delay drilling activities or cause producing wells to be shut down; |
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| · | domestic and foreign governmental regulations; and |
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| · | proximity to and capacity of transportation facilities. |
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 $20 per barrel in 2020 due in part to reduced global demand stemming from the global COVID-19 outbreak, and surging to over $120 a barrel in early March 2022, following Russia’s invasion of the Ukraine, to the $70s in recent months. 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:
| · | the domestic and foreign supply of oil, NGLs and natural gas; |
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| · | the domestic and foreign demand for oil, NGLs and natural gas; |
| · | the prices and availability of competitors’ supplies of oil, NGLs and natural gas; |
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| · | the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; |
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| · | the price and quantity of foreign imports of oil, NGLs and natural gas; |
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| · | the impact of U.S. dollar exchange rates on oil, NGLs and natural gas prices; |
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| · | domestic and foreign governmental regulations and taxes; |
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| · | speculative trading of oil, NGLs and natural gas futures contracts; |
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| · | localized supply and demand fundamentals, including the availability, proximity and capacity of gathering and transportation systems for natural gas; |
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| · | the availability of refining capacity; |
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| · | the prices and availability of alternative fuel sources; |
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| · | the threat, or perceived threat, or results, of viral pandemics, for example, as experienced with the COVID-19 pandemic in 2020 and 2021; |
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| · | weather conditions and natural disasters; |
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| · | political conditions in or affecting oil, NGLs and natural gas producing regions and/or pipelines, including in Eastern Europe, the Middle East and South America, for example, as experienced with the Russian invasion of the Ukraine in February 2022, and the current armed conflict in Israel and the Gaza Strip, which conflicts are ongoing; |
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| · | the continued threat of terrorism and the impact of military action and civil unrest; |
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| · | public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; |
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| · | the level of global oil, NGL and natural gas inventories and exploration and production activity; |
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| · | authorization of exports from the Unites States of liquefied natural gas; |
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| · | the impact of energy conservation efforts; |
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| · | technological advances affecting energy consumption; and |
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| · | overall worldwide economic conditions. |
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 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. No impairment was incurred for the years ended December 31, 2024 and 2023. In the past we have been required to impair our assets and, if conditions in any of the businesses in which we compete were to deteriorate in the future, we could determine that certain of our assets were impaired and we would then be required to write-off all or a portion of our costs for such assets. Prior write-offs have adversely affected our balance sheet and results of operations and any future significant write-offs would similarly adversely affect our balance sheet and results of operations.
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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 current Ukraine/Russia and Israel/Gaza Strip conflicts), 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 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:
| · | our estimated proved oil and natural gas reserves; |
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| · | the amount of oil and natural gas we produce from existing wells; |
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| · | the prices at which we sell our production; |
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| · | the costs of developing and producing our oil and natural gas reserves; |
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| · | our ability to acquire, locate and produce new reserves; |
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| · | the general state of the economy; |
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| · | the ability and willingness of banks to lend to us; and |
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| · | our ability to access the equity and debt capital markets. |
In addition, future events, such as terrorist attacks, wars, threat of wars, 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.
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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 quality and quantity of available data; |
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| · | the interpretation of that data; |
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| · | the judgment of the persons preparing the estimate; and |
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| · | the accuracy of the assumptions. |
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.
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:
| · | unusual or unexpected geologic formations; |
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| · | natural disasters; |
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| · | adverse weather conditions; |
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| · | unanticipated pressures; |
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| · | loss of drilling fluid circulation; |
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| · | blowouts where oil or natural gas flows uncontrolled at a wellhead; |
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| · | cratering or collapse of the formation; |
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| · | pipe or cement leaks, failures or casing collapses; |
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| · | fires or explosions; |
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| · | releases of hazardous substances or other waste materials that cause environmental damage; |
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| · | pressures or irregularities in formations; and |
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| · | equipment failures or accidents. |
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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 and Colorado, with future operations potentially extending into 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.
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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.
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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.
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We have limited control over activities on properties we do not operate.
We are not the operator on some of our properties located in our D-J Basin 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:
| · | timing and amount of capital expenditures; |
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| · | the operator’s expertise and financial resources; |
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| · | the rate of production of reserves, if any; |
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| · | approval of other participants in drilling wells; and |
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| · | selection of technology. |
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.
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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:
| · | actual prices we receive for oil and natural gas; |
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| · | actual cost and timing of development and production expenditures; |
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| · | the amount and timing of actual production; and |
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| · | changes in governmental regulations or taxation. |
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.
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If we do not hedge our exposure to reductions in oil and natural gas prices, we may be subject to significant reductions in prices. Alternatively, we may use oil and natural gas price hedging contracts, which involve credit risk and may limit future revenues from price increases and result in significant fluctuations in our profitability.
In the event that we continue to choose not to hedge our exposure to reductions in oil and natural gas prices by purchasing futures and/or by using other hedging strategies, we may be subject to a significant reduction in prices which could have a material negative impact on our profitability. Alternatively, we may elect to use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.
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.
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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.
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A substantial percentage of our Colorado and New Mexico properties, and all of our Wyoming properties, are undeveloped; therefore, the risk associated with our success is greater than would be the case if the majority of such properties were categorized as proved developed producing.
Because a substantial percentage of our Colorado and New Mexico properties, and all of our Wyoming properties, are undeveloped, we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.
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, and the D-J Basin in Weld and Morgan Counties, Colorado, and potentially extending into Laramie County, 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:
| · | drilling wells that are significantly longer and/or deeper than more conventional wells; |
| · | landing our wellbore in the desired drilling zone; |
| · | staying in the desired drilling zone while drilling horizontally through the formation; |
| · | running our casing the entire length of the wellbore; and |
| · | being able to run tools and other equipment consistently through the horizontal wellbore. |
Risks that we face while completing our wells include, but are not limited to, the following:
| · | the ability to fracture stimulate the planned number of stages in a horizontal or lateral well bore; |
| · | the ability to run tools the entire length of the wellbore during completion operations; and |
| · | the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage. |
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.
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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 $1.1 million owed to us under a secured convertible promissory note due from Tilloo in the Milnesand Sale may not be repaid.
On November 9, 2023, pursuant to the terms of the Milnesand Sale, the Company entered into a five-year secured promissory note (the “Note”) with Tilloo, bearing interest at 10% per annum, with no payments due until January 8, 2025, and fully-amortized payments due monthly over the remaining four years of the term thereafter until maturity. The Note contains customary events of default and is secured by a lien over all the assets and capital shares of EOR Operating Company (“EOR”), our prior wholly-owned subsidiary which was sold to Tilloo, created under a Security Agreement, a Security Agreement (Pledge of Corporate Securities), and a Mortgage entered into by and between the Company and Tilloo. Tilloo failed to make the initial installment payment due under the Tilloo Note on January 8, 2025. The Company issued a notice of default under the Tilloo Note to Tilloo in mid-January 2025, and the Company intends to pursue all available avenues and remedies, including potential foreclosure under the security agreement and mortgages securing the secured obligation, to resolve these matters. However, Tilloo may not make any payments under the Note and the Company may not be able to recover amounts due under the Note. Furthermore, litigation relating to the repayment of the Note, if initiated, may take away time and resources that management would otherwise have spent on other matters, which may adversely affect our results of operations and ultimately the value of our common stock.
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The requirements, restrictions and covenants in our RBL, including interest payable thereunder, may restrict our ability to operate our business and might lead to a default under such agreement.
Borrowings under the RBL 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 RBL prior to the maturity date without any premium or penalty, and is required to repay certain portions of the amounts borrowed under the RBL upon the occurrence of certain events.
The RBL includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Loan Parties from creating any indebtedness without the consent of the lenders, subject to certain exceptions, and requiring the Company to have a net leverage ratio (the ratio of (a) total net debt to (b) EBITDAX) of no less than 1.0 to 1.0 and a current ratio (the ratio of (i) consolidated current assets to (ii) consolidated current liabilities) of no less than 1.0 to 1.0. EBITDAX is defined as 'Earnings Before Interest, Taxes, Depreciation (or Depletion), Amortization, and Exploration Expense
In addition, the RBL 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 RBL immediately due and payable and take certain other actions provided for under the RBL.
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 RBL or future credit facilities. Upon the occurrence of an event of default, the lenders could elect to declare all amounts outstanding under such RBL or future debt facilities, including accrued interest or other obligations, to be immediately due and payable. If amounts outstanding under such RBL 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 RBL has a balance of $0. Amounts, if any, that we borrow under the RBL, are due on September 11, 2028.
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Our obligations under the RBL 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 RBL 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 RBL.
As a result of the above, our creditors, in the event of the occurrence of a default under the RBL, 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 RBL 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.
Dr. Simon G. Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, J. Douglas Schick, our President and newly appointed Chief Executive Officer and a member of the board, and Clark R. Moore, our Executive Vice President, General Counsel and Secretary, hold various other management positions with privately-held companies, some of which are involved in the oil and gas industry, and Dr. Kukes is the trustee and beneficiary of The SGK 2018 Revocable Trust, the Company’s largest stockholder. Dr. Kukes also beneficially owns 65.4% of our voting securities. We believe these positions require only an immaterial amount of each officer’s time and will not conflict with their roles or responsibilities with our company. If any of these companies enter into one or more transactions with our company, or if the officer’s position with any such company requires significantly more time than currently anticipated, potential conflicts of interests could arise from the officers performing services for us and these other entities.
We have in the past been significantly dependent on capital provided to us by Dr. Simon G. Kukes and may rely on Dr. Kukes for additional funding in the future.
In 2018 and 2019, Dr. Simon G. Kukes, the Company’s former Chief Executive Officer and director and current Executive Chairman of the Company's Board of Directors, loaned us an aggregate of $51.7 million to support our operations and for acquisitions through an entity owned and controlled by him, all of which loans were evidenced by promissory notes. The promissory notes generally had terms which were more favorable to us than we would have been able to obtain from third parties, including, generally favorable interest rates, no restrictions on further borrowing or financial covenants and no security interests in our assets. All of such notes have to date been converted into 29.5 million shares of common stock at conversion prices which were above the then-trading prices of our common stock. Additionally, pursuant to subscription agreements, Dr. Kukes’ entity purchased an additional aggregate of 15.0 million shares of common stock from the Company in private transactions for $28.0 million in 2019, also on substantially more favorable terms to us than could be obtained with third parties. Subsequent to September 2019, we have not received any additional capital from Dr. Kukes, instead funding our operations primarily through the sale of securities in public offerings, the sale of oil and gas properties, and sales of crude oil and natural gas. While Dr. Kukes has verbally advised us that he intends to provide us additional funding as needed, nothing has been documented to date, and such future funding, if any, may not ultimately be provided on favorable terms, if at all. In the event that we are forced to obtain funding from parties other than Dr. Kukes, such funding terms will likely not be as favorable to the Company as the funding provided by Dr. Kukes, and may not be available in such amounts as previously provided by Dr. Kukes. In the event Dr. Kukes fails to provide us future funding, when and if needed, it could have a material adverse effect on our liquidity, results of operations and could force us to borrow funds from outside sources on less favorable terms than our prior debt or sell equity to outside investors on less favorable terms than the equity we issued to Dr. Kukes.
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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 former Chief Executive Officer and newly appointed Executive Chairman of the Company's Board of Directors, Dr. Simon G. Kukes and our President and newly appointed Chief Executive Officer and a 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 Dr. Kukes and Mr. Schick. We do not believe that Dr. Kukes or Mr. Schick could be quickly replaced with personnel of equal experience and capabilities, and their successor(s) may not be as effective. If Dr. Kukes, 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. We have no employment or similar agreement in place with Dr. Kukes. 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.
Dr. Simon G. Kukes, our former Chief Executive Officer and newly appointed Executive Chairman of the Company's Board of Directors, beneficially owns 65.4% of our common stock, which gives him majority voting control over stockholder matters and his interests may be different from your interests; and as a result of such ownership, we are a “controlled company” under applicable NYSE American rules.
Dr. Simon G. Kukes, our former Chief Executive Officer and newly appointed Executive Chairman of the Company's Board of Directors, through his individual ownership of the Company and through his position as trustee and beneficiary of The SGK 2018 Revocable Trust, which beneficially owns approximately 56.7% of our issued and outstanding common stock and Dr. Kukes, together with the ownership of The SGK 2018 Revocable Trust, beneficially owns approximately 65.4% of our issued and outstanding common stock. As such, Dr. Kukes 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. Subject to any fiduciary duties owed to the stockholders generally, while Dr. Kukes’ interests may generally be aligned with the interests of our stockholders, in some instances Dr. Kukes may have interests different than the rest of our stockholders, including but not limited to, future potential company financings in which Dr. Kukes or The SGK 2018 Revocable Trust may participate, or his leadership at the Company. Dr. Kukes’ influence or control of our company as a stockholder 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 Dr. Kukes controls the stockholder vote, investors may find it difficult to replace Dr. Kukes (and such persons as he 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 Dr. Kukes may differ from the interests of the other stockholders and thus result in corporate decisions that are adverse to other stockholders. of Dr. Kukes’ 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:
| ● | a majority of the Board of Directors consist of independent directors (or 50% in the case of a smaller reporting company such as the Company); |
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| ● | the board maintain a nominations committee with prescribed duties and a written charter; and |
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| ● | the board maintain a compensation committee with prescribed duties and a written charter and comprised solely of independent directors. |
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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 Dr. Kukes 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.
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 Dr. Kukes, 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 Dr. Kukes 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
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.
Our business is subject to various forms of government regulation, including laws, regulations and federal orders concerning the location, spacing and permitting of the oil and natural gas wells we drill, among other matters. In particular, 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 4% 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.
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.
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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 Energy & Carbon Management Commission (“ECMC”) (formerly the Colorado Oil & Gas Conservation Commission (“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.
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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 4% 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:
| · | require us to apply for and receive a permit before drilling commences or certain associated facilities are developed; |
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| · | restrict the types, quantities, and concentrations of substances that can be released into the environment in connection with drilling, hydraulic fracturing, and production activities; |
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| · | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other “waters of the United States,” threatened and endangered species habitat, and other protected areas; |
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| · | require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; |
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| · | require us to add procedures and/or staff in order to comply with applicable laws and regulations; and |
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| · | impose substantial liabilities for pollution resulting from our operations. |
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, 2024, our Chief Executive Officer (“CEO”) and Chief Accounting Officer (“CAO”) 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, 2024 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.
As of December 31, 2024, there was a material weakness in our internal control over financial reporting related to the review of the inputs to the calculation of depreciation, depletion, and amortization of our reserves, including the review over the proper inclusion of all production for the current year in the reserve base for our calculation of depreciation, depletion, and amortization of our reserves. The error was identified through the course of the Company’s preparation of its year-ended December 31, 2024 financial statements. There was also a material weakness in the preparation of the tax provision. The Company has already developed a plan to implement new controls and procedures designed to address the identified material weaknesses. 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 weaknesses will be ineffective and/or that additional material weaknesses could occur regardless of the remediation or additional controls implemented by the Company.
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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.
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 actual or anticipated operating and financial performance and drilling locations, including reserves estimates; |
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| · | quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; |
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| · | changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; |
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| · | speculation in the press or investment community; |
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| · | public reaction to our press releases, announcements and filings with the SEC; |
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| · | sales of our common stock by us or other stockholders, or the perception that such sales may occur; |
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| · | the limited amount of our freely tradable common stock available in the public marketplace; |
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| · | general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices; |
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| · | the realization of any of the risk factors presented in this Annual Report; |
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| · | the recruitment or departure of key personnel; |
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| · | commencement of, or involvement in, litigation; |
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| · | the prices of oil and natural gas; |
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| · | the success of our exploration and development operations, and the marketing of any oil and natural gas we produce; |
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| · | changes in market valuations of companies similar to ours; and |
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| · | domestic and international economic, health, legal and regulatory factors unrelated to our performance. |
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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, 2024, there are outstanding stock options to purchase 1,835,667 shares of our common stock at a weighted average price per share of $1.12. 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 21,134,915 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.
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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. In order to maintain this listing, we must maintain certain share prices, financial and share distribution targets, including maintaining a minimum amount of stockholders’ equity and a minimum number of public stockholders. 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.
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.
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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:
● | Special Meetings of Stockholders — Our Bylaws provide that special meetings of the stockholders may only be called by our Chairman, our President, or upon written notice to our board of directors by our stockholders holding not less than 30% of our outstanding voting capital stock. |
● | Amendment of Bylaws — Our Bylaws may be amended by our Board of Directors alone. |
● | Advance Notice Procedures — Our Bylaws establish an advance notice procedure for stockholder proposals to be brought before an annual meeting of our stockholders. At an annual meeting, our stockholders elect a Board of Directors and transact such other business as may properly be brought before the meeting. By contrast, at a special meeting, our stockholders may transact only the business for the purposes specified in the notice of the meeting. |
● | No cumulative voting — Our Certificate of Formation and Bylaws do not include a provision for cumulative voting in the election of directors. |
● | Vacancies — Our Bylaws provide that vacancies on our Board may be filled by a majority of directors in office, although less than a quorum, and not by the stockholders. |
● | Preferred Stock — Our Certificate of Formation allows us to issue up to 100,000,000 shares of preferred stock, of which 66,625 shares have been designated as Series A preferred stock. The undesignated preferred stock may have rights senior to those of the common stock and that otherwise could adversely affect the rights and powers, including voting rights, of the holders of common stock. In some circumstances, this issuance could have the effect of decreasing the market price of the common stock as well as having an anti-takeover effect. |
● | Authorized but Unissued Shares — Our Board of Directors may cause us to issue our authorized but unissued shares of common stock in the future without stockholders’ approval. These additional shares may be utilized for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued shares of common stock could render more difficult or discourage an attempt to obtain control of a majority of our common stock by means of a proxy contest, tender offer, merger or otherwise. |
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● | Limitation of Liability and Indemnification — Our Certificate of Formation limits the liability of, and provides indemnification to, our directors and officers. |
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Additionally, Title 2, Chapter 21, Subchapter M of the Texas Business Organizations Code (the “Texas Business Combination Law”) provides that a Texas corporation may not engage in specified types of business combinations, including mergers, consolidations and asset sales, with a person, or an affiliate or associate of that person, who is an “affiliated shareholder,” for a period of three years from the date that person became an affiliated shareholder, subject to certain exceptions. An “affiliated shareholder” is generally defined as the holder of 20% or more of the corporation’s voting shares. The law’s prohibitions do not apply if the business combination or the acquisition of shares by the affiliated shareholder was approved by the Board of Directors of the corporation before the affiliated shareholder became an affiliated shareholder; or the business combination was approved by the affirmative vote of the holders of at least two-thirds of the outstanding voting shares of the corporation not beneficially owned by the affiliated shareholder, at a meeting of shareholders called for that purpose, not less than six months after the affiliated shareholder became an affiliated shareholder. Because we have more than 100 of record shareholders, we are considered an “issuing public corporation” for purposes of this law. The Texas Business Combination Law does not apply to the following: the business combination of an issuing public corporation: where the corporation’s original charter or bylaws contain a provision expressly electing not to be governed by the Texas Business Combination Law; or that adopts an amendment to its charter or bylaws, by the affirmative vote of the holders, other than affiliated shareholders, of at least two-thirds of the outstanding voting shares of the corporation, expressly electing not to be governed by the Texas Business Combination Law and so long as the amendment does not take effect for 18 months following the date of the vote and does not apply to a business combination with an affiliated shareholder who became affiliated on or before the effective date of the amendment; a business combination of an issuing public corporation with an affiliated shareholder that became an affiliated shareholder inadvertently, if the affiliated shareholder divests itself, as soon as possible, of enough shares to no longer be an affiliated shareholder and would not at any time within the three-year period preceding the announcement of the business combination have been an affiliated shareholder but for the inadvertent acquisition; a business combination with an affiliated shareholder who became an affiliated shareholder through a transfer of shares by will or intestacy and continuously was an affiliated shareholder until the announcement date of the business combination; or a business combination of a corporation with its wholly-owned Texas subsidiary if the subsidiary is not an affiliate or associate of the affiliated shareholder other than by reason of the affiliated shareholder’s beneficial ownership of voting shares of the corporation.
The existence of the foregoing provisions and anti-takeover measures could limit the price that investors might be willing to pay in the future for shares of our common stock. They could also deter potential acquirers of our company, thereby reducing the likelihood that you could receive a premium for your common stock in an acquisition.
Our Board of Directors can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of our company more difficult even if it might benefit our stockholders.
Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Shares of preferred stock may be issued by our Board of Directors without stockholder approval, with voting powers and such preferences and relative, participating, optional or other special rights and powers as determined by our Board of Directors, which may be greater than the shares of common stock currently outstanding. As a result, shares of preferred stock may be issued by our Board of Directors which cause the holders to have majority voting power over our shares, provide the holders of the preferred stock the right to convert the shares of preferred stock they hold into shares of our common stock, which may cause substantial dilution to our then common stock stockholders and/or have other rights and preferences greater than those of our common stock stockholders including having a preference over our common stock with respect to dividends or distributions on liquidation or dissolution.
Investors should keep in mind that the Board of Directors has the authority to issue additional shares of common stock and preferred stock, which could cause substantial dilution to our existing stockholders. Additionally, the dilutive effect of any preferred stock which we may issue may be exacerbated given the fact that such preferred stock may have voting rights and/or other rights or preferences which could provide the preferred stockholders with substantial voting control over us subsequent to the date of this Annual Report and/or give those holders the power to prevent or cause a change in control, even if that change in control might benefit our stockholders. As a result, the issuance of shares of common stock and/or preferred stock may cause the value of our securities to decrease.
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General Risk Factors
If we complete acquisitions or enter into business combinations in the future, they may disrupt or have a negative impact on our business.
If we complete acquisitions or enter into business combinations in the future, funding permitting, we could have difficulty integrating the acquired companies’ assets, personnel and operations with our own. Additionally, acquisitions, mergers or business combinations we may enter into in the future could result in a change of control of the Company, and a change in the Board of Directors or officers of the Company. In addition, the key personnel of the acquired business may not be willing to work for us. We cannot predict the effect expansion may have on our core business. Regardless of whether we are successful in making an acquisition or completing a business combination, the negotiations could disrupt our ongoing business, distract our management and employees and increase our expenses. In addition to the risks described above, acquisitions and business combinations are accompanied by a number of inherent risks, including, without limitation, the following:
| · | the difficulty of integrating acquired companies, concepts and operations; |
| · | the potential disruption of the ongoing businesses and distraction of our management and the management of acquired companies; |
| · | change in our business focus and/or management; |
| · | difficulties in maintaining uniform standards, controls, procedures and policies; |
| · | the potential impairment of relationships with employees and partners as a result of any integration of new management personnel; |
| · | the potential inability to manage an increased number of locations and employees; |
| · | our ability to successfully manage the companies and/or concepts acquired; |
| · | the failure to realize efficiencies, synergies and cost savings; or |
| · | the effect of any government regulations which relate to the business acquired. |
Our business could be severely impaired if and to the extent that we are unable to succeed in addressing any of these risks or other problems encountered in connection with an acquisition or business combination, many of which cannot be presently identified. These risks and problems could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations.
Any acquisition or business combination transaction we enter into in the future could cause substantial dilution to existing stockholders, result in one party having majority or significant control over the Company or result in a change in business focus of the Company.
We may incur indebtedness which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs.
We currently have no outstanding indebtedness, but we may incur significant amounts of indebtedness in the future in order to make acquisitions or to develop our properties. Our level of indebtedness could affect our operations in several ways, including the following:
| · | a significant portion of our cash flows could be used to service our indebtedness; |
| · | a high level of debt would increase our vulnerability to general adverse economic and industry conditions; |
| · | any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; |
| · | a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness may prevent us from pursuing; and |
| · | debt covenants to which we may agree may affect our flexibility in planning for, and reacting to, changes in the economy and in our industry. |
A high level of indebtedness increases the risk that we may default on our debt obligations. We may not be able to generate sufficient cash flows to pay the principal or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. If we do not have sufficient funds and are otherwise unable to arrange financing, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our business, financial condition and results of operations.
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Because we are a small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act and the Dodd-Frank Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company with listed equity securities, we must comply with the federal securities laws, rules and regulations, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and the Dodd-Frank Act, related rules and regulations of the SEC and the NYSE American, with which a private company is not required to comply. Complying with these laws, rules and regulations will occupy a significant amount of time of our Board of Directors and management and will significantly increase our costs and expenses, which we cannot estimate accurately at this time. Among other things, we must:
| · | establish and maintain a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board; |
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| · | comply with rules and regulations promulgated by the NYSE American; |
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| · | prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; |
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| · | maintain various internal compliance and disclosures policies, such as those relating to disclosure controls and procedures and insider trading in our common stock; |
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| · | involve and retain to a greater degree outside counsel and accountants in the above activities; |
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| · | maintain a comprehensive internal audit function; and |
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| · | maintain an investor relations function. |
In addition, being a public company subject to these rules and regulations may require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our Board of Directors, particularly to serve on our audit committee, and qualified executive officers.
We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock.
We do not presently intend to pay any cash dividends on our common stock or to repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of the Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price paid by you.
Our business could be adversely affected by security threats, including cybersecurity threats.
We face various security threats, including cybersecurity threats to gain unauthorized access to our sensitive information, to seek initiation of unauthorized fund transfers, or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, refineries, rail facilities and pipelines. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition and results of operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruptions, or other disruptions to our operations.
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Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, reputational damage, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position and results of operations.
Future sales of our common stock could cause our stock price to decline.
If we or our shareholders sell substantial amounts of our common stock in the public market, the market price of our common stock could decrease significantly. The perception in the public market that we or our shareholders might sell shares of our common stock could also depress the market price of our common stock. Additionally, if we or our existing shareholders sell, or indicate an intention to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. The market price for shares of our common stock may drop significantly when such securities are sold in the public markets. A decline in the price of shares of our common stock might impede our ability to raise capital through the issuance of additional shares of our common stock or other equity securities.
The threat and impact of terrorist attacks, cyber-attacks or similar hostilities may adversely impact our operations.
We cannot assess the extent of either the threat or the potential impact of future terrorist attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such hostilities may affect our operations in unpredictable ways, including the possibility that infrastructure facilities, including pipelines and gathering systems, production facilities, processing plants and refineries, could be targets of, or indirect casualties of, an act of terror, a cyber-attack or electronic security breach, or an act of war.
We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.
Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.
Failure to adequately protect critical data and technology systems could materially affect our operations.
Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows.
Stockholders may be diluted significantly through our efforts to obtain financing and satisfy obligations through the issuance of securities.
Wherever possible, our Board of Directors will attempt to use non-cash consideration to satisfy obligations. In many instances, we believe that the non-cash consideration will consist of shares of our common stock, preferred stock or warrants to purchase shares of our common stock. Our Board of Directors has authority, without action or vote of the stockholders, subject to the requirements of the NYSE American (which generally require stockholder approval for any transactions which would result in the issuance of more than 20% of our then outstanding shares of common stock or voting rights representing over 20% of our then outstanding shares of stock, subject to certain exceptions, including sales in a public offering and/or sales which are undertaken at or above the lower of the closing price immediately preceding the signing of the binding agreement or the average closing price for the five trading days immediately preceding the signing of the binding agreement), to issue all or part of the authorized but unissued shares of common stock, preferred stock or warrants to purchase such shares of common stock. In addition, we may attempt to raise capital by selling shares of our common stock, possibly at a discount to market in the future. These actions will result in dilution of the ownership interests of existing stockholders and may further dilute common stock book value, and that dilution may be material. Such issuances may also serve to enhance existing management’s ability to maintain control of us, because the shares may be issued to parties or entities committed to supporting existing management.
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Securities analysts may not cover, or continue to cover, our common stock and this may have a negative impact on our common stock’s market price.
The trading market for our common stock will depend, in part, on the research and reports that securities or industry analysts publish about us or our business. We do not have any control over independent analysts (provided that we may engage various non-independent analysts). We currently only have a few independent analysts that cover our common stock, and these analysts may discontinue coverage of our common stock at any time. Further, we may not be able to obtain additional research coverage by independent securities and industry analysts. If no independent securities or industry analysts continue coverage of us, the trading price for our common stock could be negatively impacted. If one or more of the analysts who covers us downgrades our common stock, changes their opinion of our shares or publishes inaccurate or unfavorable research about our business, our stock price could decline. If one or more of these analysts ceases coverage of us or fails to publish reports on us regularly, demand for our common stock could decrease and we could lose visibility in the financial markets, which could cause our stock price and trading volume to decline.
If persons engage in short sales of our common stock, including sales of shares to be issued upon exercise of our outstanding warrants, the price of our common stock may decline.
Selling short is a technique used by a stockholder to take advantage of an anticipated decline in the price of a security. In addition, holders of options and warrants will sometimes sell short knowing they can, in effect, cover through the exercise of an option or warrant, thus locking in a profit. A significant number of short sales or a large volume of other sales within a relatively short period of time can create downward pressure on the market price of a security. Further sales of common stock issued upon exercise of our outstanding warrants could cause even greater declines in the price of our common stock due to the number of additional shares available in the market upon such exercise, which could encourage short sales that could further undermine the value of our common stock. Stockholders could, therefore, experience a decline in the values of their investment as a result of short sales of our common stock.
The Company does not insure against all potential losses, which could result in significant financial exposure.
The Company does not have commercial insurance or third-party indemnities to fully cover all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result, the Company is, to a substantial extent, self-insured for such events. The Company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would arise from such an event or series of events. The occurrence of a significant incident, series of events, or unforeseen liability for which the Company is self-insured, not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the Company’s results of operations or financial condition.
Increasing attention to environmental, social, and governance (“ESG”) matters may impact our business.
Increasing attention to ESG matters, including those related to climate change and sustainability, increasing societal, investor and legislative pressure on companies to address ESG matters, may result in increased costs, reduced profits, increased investigations and litigation or threats thereof, negative impacts on our stock price and access to capital markets, and damage to our reputation. Increasing attention to climate change, for example, may result in demand shifts for hydrocarbon and additional governmental investigations and private litigation, or threats thereof, against the Company. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, including climate change and climate-related risks. Such ratings are used by some investors to inform their investment and voting decisions. Also, some stakeholders, including but not limited to sovereign wealth, pension, and endowment funds, have been divesting and promoting divestment of or screening out of fossil fuel equities and urging lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Unfavorable ESG ratings and investment community divestment initiatives, among other actions, may lead to negative investor sentiment toward the Company and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Additionally, evolving expectations on various ESG matters, including biodiversity, waste and water, may increase costs, require changes in how we operate and lead to negative stakeholder sentiment.
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Global economic conditions could materially adversely affect our business, results of operations, financial condition and growth.
Adverse macroeconomic conditions, including inflation, slower growth or recession, new or increased tariffs, changes to fiscal and monetary policy, tighter credit, higher interest rates, high unemployment and currency fluctuations could materially adversely affect our operations, expenses, access to capital and the market for oil and gas. In addition, uncertainty about, or a decline in, global or regional economic conditions could have a significant impact on our expected funding sources, suppliers and partners. A downturn in the economic environment could also lead to limitations on our ability to issue new debt; reduced liquidity; and declines in the fair value of our financial instruments. These and other economic factors could materially adversely affect our business, results of operations, financial condition and growth.
We may be adversely affected by climate change or by legal, regulatory or market responses to such change.
The long-term effects of climate change are difficult to predict; however, such effects may be widespread. Impacts from climate change may include physical risks (such as rising sea levels or frequency and severity of extreme weather conditions), social and human effects (such as population dislocations or harm to health and well-being), compliance costs and transition risks (such as regulatory or technology changes) and other adverse effects. The effects of climate change could increase the cost of certain products, commodities and energy (including utilities), which in turn may impact our ability to procure goods or services required for the operation of our business. Climate change could also lead to increased costs as a result of physical damage to or destruction of our facilities, equipment and business interruption due to weather events that may be attributable to climate change. These events and impacts could materially adversely affect our business operations, financial position or results of operation.
We might be adversely impacted by changes in accounting standards.
Our consolidated financial statements are subject to the application of U.S. GAAP, which periodically is revised or reinterpreted. From time to time, we are required to adopt new or revised accounting standards issued by recognized authoritative bodies, including the Financial Accounting Standards Board (“FASB”) and the SEC. It is possible that future accounting standards may require changes to the accounting treatment in our consolidated financial statements and may require us to make significant changes to our financial systems. Such changes might have a materially adverse impact on our financial position or results of operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 1C. CYBERSECURITY
The Company understands the importance of preventing, assessing, identifying, and managing material risks associated with cybersecurity threats. Cybersecurity processes to assess, identify and manage risks from cybersecurity threats have been incorporated as a part of the Company’s overall risk assessment process. These risks include, among other things: operational risks, intellectual property theft, fraud, extortion, harm to employees or customers and violation of data privacy or security laws.
We have processes in place to identify, assess and monitor material risks from cybersecurity threats, including the material risks of the Company. These processes are part of our overall enterprise risk management process and have been embedded in our operating procedures, internal controls and information systems. On a regular basis we implement into our operations these cybersecurity processes, technologies, and controls to assess, identify, and manage material risks. Cybersecurity risks related to our business, technical operations, privacy and compliance issues are identified and addressed through a multi-faceted approach including third party assessments, IT security, governance, risk and compliance reviews. To defend, detect and respond to cybersecurity incidents, we, among other things, implemented (i) multi-factor authentication and password protection requirements for accessing all Company systems and applications such as Company electronic mail and the Company’s banking and accounting environments, (ii) a secure email gateway using GoSecure that combines machine learning, behavioral scanning, exploit detection, signature-based detection and structure heuristics to provide defense against phishing and business electronic mail compromise attacks, spam, polymorphic malware, theft and other dangerous offensive content, (iii) endpoint protection using Microsoft Defender on Company and employee computers and Company-provided devices, (iii) a physical networking room with restricted access to only authorized personnel, (iv) regular cybersecurity training, awareness, and threat updates programs to keep all Company personnel updated and informed regarding emerging threats and best practices, and (v) daily cloud backups of the Company’s accounting environment.
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Incidents are evaluated to determine materiality as well as operational and business impact, and reviewed for privacy impact.
We describe whether and how risks from identified cybersecurity threats, including as a result of any previous cybersecurity incidents, have materially affected or are reasonably likely to materially affect us, including our business strategy, results of operations, or financial condition, under the heading “Failure of our information technology systems, including cybersecurity attacks or other data security incidents, could significantly disrupt the operation of our business.” included as part of our risk factor disclosures at Item 1A of this Annual Report on Form 10-K.
Cybersecurity is an important part of our risk management processes and an area of focus for our Board and management.
Our management team is
As of and for the year ended December 31, 2024, there have been no cybersecurity incidents that have
Although we have designed our cybersecurity program and governance procedures discussed above to mitigate cybersecurity risks, we may in the future experience cybersecurity risks, threats and attacks. To date, no risks, threats or attacks have had a material impact on our operations, business strategy or financial results, but we cannot provide assurance that they will not have a material impact on us in the future. See the section entitled “Risk Factors” included elsewhere in this Annual Report for further information. We continuously work to enhance our cybersecurity risk management program.
ITEM 2. PROPERTIES.
The information regarding the Company’s oil and gas properties as required by Item 102 of Regulation S-K is included in “Item 1. Business”, above and incorporated in this Item 2 by reference. Additional information regarding our oil and gas properties can be found in “Part II” - “Item 8 Financial Statements and Supplementary Data” – “Supplemental Oil and Gas Disclosures (Unaudited)”.
Office Leases
The Company had a lease for its corporate offices in Houston, Texas on approximately 5,200 square feet of office space that expired on August 31, 2023 and had a base monthly rent of approximately $10,000. In December 2022, the Company entered into a lease agreement for its existing office space that commenced on September 1, 2023, and expires on February 28, 2027. The base monthly rent is approximately $9,200 for the first 18 months and increases to approximately $9,500 thereafter. The Company paid both a security deposit and prepaid rent for $14,700, respectively.
For the years ended December 31, 2024 and 2023, the Company incurred lease expense of $110,000, for the lease.
The Company believes its existing leased office space is suitable for the conduct of its business. We believe that this arrangement is suitable for the conduct of our business.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may become party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings that we believe could reasonably be expected to have a material adverse effect on our business, prospects, financial condition or results of operations. We may become involved in material legal proceedings in the future.
ITEM 4. MINE SAFETY DISCLOSURES.
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
Since September 10, 2013, the Company’s shares of common stock have traded on the NYSE American under the ticker symbol “PED.”
Stockholders
As of March 28, 2025, there were 91,339,385 shares of our common stock issued and outstanding held by approximately 614 holders of record of our common stock, not including any persons who hold their stock in “street name”.
Dividend Policy
We do not currently intend to pay any cash dividends on our common stock in the foreseeable future. We expect to retain all available funds and future earnings, if any, to fund the development and growth of our business. Any future determination to pay dividends, if any, on our common stock will be at the discretion of our Board of Directors and will depend on, among other factors, our results of operations, financial condition, capital requirements and contractual restrictions.
Common Stock
The Company is authorized to issue 200,000,000 shares of common stock with $0.001 par value per share. Holders of shares of common stock are entitled to one vote per share on each matter submitted to a vote of stockholders. In the event of liquidation, holders of common stock are entitled to share pro rata in the distribution of assets remaining after payment of liabilities, if any. Holders of common stock have no cumulative voting rights, and, accordingly, the holders of a majority of the outstanding shares have the ability to elect all of the directors of the Company. Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock are entitled to such dividends as may be declared by the Board out of funds legally available, therefore. The outstanding shares of common stock are validly issued, fully paid and non-assessable.
Preferred Stock
At December 31, 2024, and as of the date of this filing, the Company was authorized to issue 100,000,000 shares of preferred stock with a par value of $0.001 per share, of which 25,000,000 shares have been designated “Series A Convertible Preferred Stock”. As of December 31, 2024, and 2023, there were no shares of the Company’s Series A Convertible Preferred Stock outstanding, respectively, and there are no outstanding shares of preferred stock as of the date of this filing.
Stock Transfer Agent
Our stock transfer agent is Equiniti Trust Company, LLC located at 48 Wall Street, Floor 23 New York, NY 10005.
Recent Sales of Unregistered Securities
There have been no sales of unregistered securities during the quarter ended December 31, 2024 and from the period from January 1, 2025 to the filing date of this report, which have not previously been disclosed in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K.
Purchases of Equity Securities by The Issuer and Affiliated Purchasers
None.
ITEM 6. [RESERVED]
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Risk Factors” and “Forward-Looking Statements.”
The discussion in this section has been impacted by the restatement described in the Explanatory Note at the beginning of this Annual Report on Form 10-K and in Note 4 of the consolidated financial statements. Certain of the financial and other information provided in this Management’s Discussion and Analysis of our financial condition and results of operations has been updated to reflect the restatement adjustments.
Summary of The Information Contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is provided in addition to the accompanying consolidated financial statements and notes to assist readers in understanding our results of operations, financial condition, and cash flows. Our MD&A is organized as follows:
| · | Overview. Discussion of our business and overall analysis of financial and other highlights affecting us, to provide context for the remainder of our MD&A. |
|
|
|
| · | Results of Operations. An analysis of our financial results comparing the years ended December 31, 2024 and 2023. |
|
|
|
| · | Liquidity and Capital Resources. An analysis of changes in our consolidated balance sheets and cash flows and discussion of our financial condition. |
|
|
|
| · | Critical Accounting Estimates. Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts. |
Overview
We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies. Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico and in the Denver-Julesberg Basin in Colorado and Wyoming. As of December 31, 2024, we held approximately 14,105 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, PEDCO, and which are operated by our wholly-owned operating subsidiary, RAZO, which asset we refer to as our “Permian Basin Asset.” Also as of December 31, 2024, we held approximately 14,809 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and 3,860 net D-J Basin acres located in Laramie County, Wyoming, through our wholly-owned subsidiary, PRH, and which are operated by our wholly-owned operating subsidiary, Red Hawk, which asset we refer to as our “D-J Basin Asset.” As of December 31, 2024, we held interests in 35 gross (33.5 net) wells in our Permian Basin Asset, of which 28 gross (26.5 net) wells are active producers, five gross (five net) wells are inactive, and two gross (two net) wells are active salt water disposal wells (“SWD’s”), all of which are held by PEDCO and operated by RAZO, and interests in 82 gross (21.9 net) wells in our D-J Basin Asset held by PRH, all of which 17 gross (15.4 net) wells are operated by Red Hawk and currently producing, 48 gross (6.5 net) wells are non-operated, and 17 wells have an after-payout interest.
Detailed information about our business plans and operations, including our core D-J Basin and Permian Basin Assets, is contained under “Part 1” — “Item 1. Business” above.
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How We Conduct Our Business and Evaluate Our Operations
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe have significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
| · | production volumes; |
| · | realized prices on the sale of oil and natural gas; |
| · | oil and natural gas production and operating expenses; |
| · | capital expenditures; |
| · | general and administrative expenses; |
| · | net cash provided by operating activities; and |
| · | net income. |
Reserves
Our estimated net proved crude oil and natural gas reserves at December 31, 2024 and 2023 were approximately 18.1 million barrels of oil equivalent (“MMBoe”) and 17.0 MMBoe, respectively. The 1.1 MMBoe increase was primarily due to the addition of proved undeveloped reserves in our D-J Basin Asset as a result of increased activity around our acreage and favorable pricing.
Using the average monthly crude oil price of $75.48 per barrel (“Bbl”) and natural gas price of $2.13 per thousand cubic feet (“Mcf”) for the twelve months ended December 31, 2024, our estimated discounted future net cash flow (“PV-10”) for our proved reserves was approximately $178.9 million, of which approximately $104.3 million are proved undeveloped reserves. Total reserve value at December 31, 2024, represents a decrease of approximately $52.8 million or 23% from approximately $231.7 million a year earlier using the same SEC pricing and reserves methodology. The decrease is primarily attributable to commodity pricing, as the average SEC pricing for 2024, noted above, was lower than the 2023 average pricing of $78.22 per Bbl for crude oil and $2.64 per Mcf for natural gas.
The reserves as of December 31, 2024 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc. A large portion of the proved undeveloped crude oil reserves are associated with our D-J Basin Asset. Although these hydrocarbon quantities have been determined in accordance with industry standards, they are prepared using the subjective judgments of the independent engineers and may actually be more or less.
Oil and Natural Gas Sales Volumes
During the year ended December 31, 2024, our net crude oil, natural gas, and NGLs sales volumes increased to 671,796 Bbls, or 1,835 barrels of oil per day (“Bopd”), from 520,886 Bbls, or 1,427 Bopd, a 29% increase over the previous fiscal year. The increase in production volume is related to our participation in 24 new non-operated wells (11 of which occurred in the latter four months of 2024) in the D-J Basin and the drilling and completion of three operated wells with a third-party in the Permian Basin in the latter part of Q1 2024 (see additional detail below).
Significant Capital Expenditures
The table below sets out the significant components of capital expenditures for the year ended December 31, 2024 (in thousands):
Capital Expenditures |
|
|
| |
Leasehold Acquisitions |
| $ | 862 |
|
Mineral Acquisitions |
|
| 725 |
|
Drilling and Facilities |
|
| 20,522 |
|
Total* |
| $ | 22,109 |
|
*see “Item 8. Financial Statements and Supplementary Data” - “Note 7 - Oil and Gas Properties”.
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Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. We expect prices to remain volatile for the remainder of the year. For information about the impact of realized commodity prices on our crude oil and natural gas and condensate revenues, refer to “Results of Operations” below.
Results of Operations
The following discussion and analysis of the results of operations for each of the two fiscal years in the years ended December 31, 2024 and 2023 should be read in conjunction with the consolidated financial statements of PEDEVCO Corp. and notes thereto included herein (see “Item 8. Financial Statements and Supplementary Data”).
Net Income
We reported net income for the year ended December 31, 2024 of $17.8 million, or $0.20 per share, compared to net income for the year ended December 31, 2023 of $1.7 million or $0.02 per share. The increase in net income of $16.1 million was primarily due to a recognition of an income tax benefit of $12.8 million (see “Item 8. Financial Statements and Supplementary Data” - “Note 14 – Income Taxes”) coupled with $8.8 million increase in revenue in the current period and a $4.3 million loss on the Milnesand Sale in the prior period, offset by a $9.5 million increase in total operating expenses in the current period, offset further by a $0.2 million decrease in other income and a $0.1 million loss on sale of oil and gas properties in the current period (all of which are discussed in more detail below).
Net Revenues
The following table sets forth the revenue and production data for the years ended December 31, 2024 and 2023:
|
| 2024 |
|
| 2023 |
|
| Increase (Decrease) |
|
| Increase (Decrease) |
| ||||
Sale Volumes: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Crude Oil (Bbls) |
|
| 492,396 |
|
|
| 382,794 |
|
|
| 109,602 |
|
|
| 29% | |
Natural Gas (Mcf) |
|
| 608,382 |
|
|
| 479,533 |
|
|
| 128,849 |
|
|
| 27% | |
NGL (Bbls) |
|
| 78,003 |
|
|
| 58,170 |
|
|
| 19,833 |
|
|
| 34% | |
Total (Boe) (1) |
|
| 671,796 |
|
|
| 520,886 |
|
|
| 150,910 |
|
|
| 29% | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (Bbls per day) |
|
| 1,345 |
|
|
| 1,049 |
|
|
| 296 |
|
|
| 28% | |
Natural Gas (Mcf per day) |
|
| 1,662 |
|
|
| 1,314 |
|
|
| 348 |
|
|
| 26% | |
NGL (Bbls per day) |
|
| 213 |
|
|
| 159 |
|
|
| 54 |
|
|
| 34% | |
Total (Boe per day) (1) |
|
| 1,835 |
|
|
| 1,427 |
|
|
| 408 |
|
|
| 29% | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sale Price: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil ($/Bbl) |
| $ | 73.50 |
|
| $ | 72.95 |
|
| $ | 0.55 |
|
|
| 1% | |
Natural Gas($/Mcf) |
|
| 2.00 |
|
|
| 3.00 |
|
|
| (1.00 | ) |
| (33%) |
| |
NGL ($/Bbl) |
|
| 27.48 |
|
|
| 24.43 |
|
|
| 3.05 |
|
|
| 13% | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating Revenues (In thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
| $ | 36,193 |
|
| $ | 27,925 |
|
| $ | 8,268 |
|
|
| 30% | |
Natural Gas |
|
| 1,216 |
|
|
| 1,438 |
|
|
| (222 | ) |
| (15%) |
| |
NGL |
|
| 2,144 |
|
|
| 1,421 |
|
|
| 723 |
|
|
| 51% | |
Total Revenues |
| $ | 39,553 |
|
| $ | 30,784 |
|
| $ | 8,769 |
|
|
| 28% | |
(1) | Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil. |
Total crude oil, natural gas and NGL revenues for the year ended December 31, 2024, increased $8.8 million, or 28%, to $39.6 million, compared to $30.8 million for the same period a year ago, due to a favorable volume variance of $8.8 million. There was a negligible price variance over the periods. The increase in production volume is related to our participation in 24 new non-operated wells in the D-J Basin and the drilling and completion of three operated wells in the Permian Basin.
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| Table of Contents |
Net Operating and Other (Income) Expenses
The following table sets forth operating and other expenses for the years ended December 31, 2024 and 2023 (in thousands):
|
| 2024 |
|
| 2023 |
|
| Increase (Decrease) |
|
| % Increase (Decrease) |
| ||||
|
|
|
| (As Restated) |
|
|
|
|
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Direct Lease Operating Expense |
| $ | 6,961 |
|
| $ | 4,679 |
|
| $ | 2,282 |
|
|
| 49% | |
Workovers |
|
| 839 |
|
|
| 1,460 |
|
|
| (621 | ) |
| (43%) |
| |
Other* |
|
| 4,649 |
|
|
| 3,571 |
|
|
| 1,078 |
|
|
| 30% | |
Loss on settlement of ARO |
|
| - |
|
|
| 121 |
|
|
| (121 | ) |
| (100%) |
| |
Lease Operating Expenses |
| $ | 12,449 |
|
| $ | 9,831 |
|
| $ | 2,618 |
|
|
| 27% | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization and Accretion |
|
| 15,920 |
|
|
| 9,440 |
|
|
| 6,480 |
|
|
| 69% | |
General and Administrative (Cash) |
| $ | 4,532 |
|
| $ | 3,965 |
|
| $ | 567 |
|
|
| 14% | |
Share-Based Compensation (Non-Cash) |
|
| 1,859 |
|
|
| 2,043 |
|
|
| (184 | ) |
| (9%) |
| |
Total General and Administrative Expense |
| $ | 6,391 |
|
| $ | 6,008 |
|
| $ | 383 |
|
|
| 6% | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on Sale of Oil and Gas Properties |
|
| 76 |
|
|
| 4,268 |
|
|
| (4,192 | ) |
| (98%) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Income |
| $ | 351 |
|
| $ | 422 |
|
| $ | (71 | ) |
| (17%) |
| |
Other Income (Expense) |
| $ | (42 | ) |
| $ | 40 |
|
| $ | (82 | ) |
| (205%) |
| |
Gain on Sale of Fixed Asset |
| $ | 12 |
|
| $ | - |
|
| $ | 12 |
|
|
| 100% | |
*Includes severance, ad valorem taxes, workover adjustments and assessment and marketing costs.
Lease Operating Expenses. The increase of $2.6 million was primarily due to higher direct and variable lease operating expenses associated with the higher oil volume resulting from the increased number of wells and increased oil and gas production during the current year’s period, compared to the prior year’s period.
Depreciation, Depletion, Amortization and Accretion. The $5.9 million increase was primarily the result of an increase in production (noted above) in the current period when compared to the prior period. Additionally, the Company continued to adhere to its plugging and abandonment program in the Permian Basin Asset (in accordance with the terms of an existing compliance order) to plug additional wells over the next several years, which increased accretion expense in Q4 2024 by approximately $0.4 million.
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| Table of Contents |
General and Administrative Expenses (excluding share-based compensation). The increase of $0.6 million in general and administrative expenses (excluding share-based compensation) was primarily due to increased contract and full time staff related to increased activity, an increase in accrued bonuses, which were subsequently paid in January 2025, software licensing fees and general increases in accounting and professional services when comparing the prior period to the current period.
Share-Based Compensation. Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, decreased nominally due to the forfeiture of certain employee stock-based options due to certain voluntary employee terminations. Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations.
Loss on Sale of Oil and Gas Properties, net. The Company completed three oil and gas property sales transactions during the year ended December 31, 2024, for a total net loss on the sale of oil and gas properties of $76,000, as follows: (i) the Company sold 30 gross (5.1 net) non-operated legacy well-bores in its D-J Basin Asset for net cash proceeds of $90,000 during 2024, resulting in the Company recognizing a loss on sale of oil and gas properties of $865,000 for these non-core assets, while noting. the Company still retained the corresponding acreage related to the sale for any potential future development; (ii) the Company sold a legacy well-bore assignment for net cash proceeds of $25,000 and recognized a gain on sale of oil and gas properties of $29,000; and (iii) the Company sold leasehold rights to 320 net acres located in the D-J Basin for net cash proceeds of $750,000 and recognized a corresponding gain on sale of oil and gas properties of $735,000, as the leasehold costs had been fully depleted. In the prior period, the Company sold its then-wholly-owned subsidiary EOR Operating Company and related assets in the November 2023 Milnesand Sale and recognized the corresponding loss of $4.3 million. (see “Item 8. Financial Statements and Supplementary Data” - “Note 7 - Oil and Gas Properties”).
Interest Income and Other (Expense) Income. Includes interest earned from our interest-bearing cash accounts, for which interest rates have remained relatively flat in the current period, compared to the prior period, and interest on our note receivable. Other expense in the current period primarily relates to the subsequent disposition of a cash escrow bank balance related to the Milnesand Sale. Other income in the prior period is primarily related to the sale of used pipe.
Gain on Sale of Fixed Asset. Relates to the sale of a vehicle and the subsequent purchase of another vehicle in the current period.
Liquidity and Capital Resources
The primary sources of cash for the Company during the year ended December 31, 2024 were from $39.6 million in sales of crude oil and natural gas. The primary uses of cash were funds used for drilling, completion, acquisition and operating costs.
Working Capital
At December 31, 2024, the Company’s total current assets of $13.2 million exceeded its total current liabilities of $6.9 million, resulting in a working capital surplus of $6.3 million, while at December 31, 2023, the Company’s total current assets of $24.6 million exceeded its total current liabilities of $18.9 million, resulting in a working capital surplus of $5.7 million. Although current assets and current liabilities both decreased when comparing periods, the $0.6 million net increase in our working capital surplus is primarily related to a larger reduction in accounts payable and accrued expenditures compared to the corresponding smaller reduction in current assets when comparing the current period to the prior period due to the timing of cash payments related to our drilling, as operator, and our participation in the drilling and completion of wells by a third-party operator. (see “Item 8. Financial Statements and Supplementary Data” - “Note 7 - Oil and Gas Properties”).
Financing
The Company has an ongoing $8.0 million offering of securities in an “at the market offering”, pursuant to which the Company may sell securities from time to time (the “ATM Offering”). The ATM Offering was made pursuant to the terms of a December 20, 2024, Sales Agreement (the “Sales Agreement”) with Roth Capital Partners, LLC and A.G.P./Alliance Global Partners. The Company will pay the Lead Agent a commission of 3.0% of the gross sales price of any shares sold under the Sales Agreement. The Company also agreed to reimburse the Agents for their reasonable and documented out-of-pocket expenses in an amount not to exceed $75,000, in connection with entering into the Sales Agreement and for the Agents’ reasonable and documented out-of-pocket expenses related to quarterly maintenance of the Sales Agreement on a quarterly basis in an amount not to exceed $5,000. The Company has not sold any securities under the ATM Offering as of the date of this report.
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Our net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million, including $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2.5 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses. We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and Area of Mutual Interest (AMI) entered into in August 2024 with a private operator. This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated. We periodically review our capital expenditures and adjust our capital forecasts and allocations based on liquidity, drilling results, leasehold acquisition opportunities, partner non-consents, proposals from third party operators, and commodity prices, while prioritizing our financial strength and liquidity (see “Part I” – “Item 1A. Risk Factors”).
We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective. If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and nearly 100% held by production (“HBP”), allowing for flexibility of timing on development. Our 2025 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.
We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) borrowing under our reserve-based lending facility (“RBL”) with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $20 million and an aggregate maximum revolving credit amount of $250 million (of which none has been drawn down by the Company to date), (iv) equity infusions or loans (which may be convertible) made available from Dr. Simon G. Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, which funding Dr. Kukes is under no obligation to provide, (v) public or private debt or equity financings, including up to $8.0 million in securities which we may sell in the future in “at the market offerings”, pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the “Lead Agent”), and A.G.P./Alliance Global Partners (“AGP” and, together with the Lead Agent, the “Agents”)(discussed in greater detail below under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing” (under which we have sold no shares to date), and (vi) funding through other credit or loan facilities. In addition, we may seek additional funding through asset sales, farm-out arrangements, and partnerships to fund potential acquisitions during the remainder of 2025.
Cash Flows (in thousands)
|
| Year Ended December 31, |
| |||||
|
| 2024 |
|
| 2023 |
| ||
Cash flows provided by operating activities |
| $ | 12,766 |
|
| $ | 23,481 |
|
Cash flows used in investing activities |
|
| (26,874 | ) |
|
| (35,743 | ) |
Cash flows provided by financing activities |
|
| - |
|
|
| - |
|
Net decrease in cash and restricted cash |
| $ | (14,108 | ) |
| $ | (12,262 | ) |
Cash provided by operating activities. Net cash provided by operating activities decreased by $10.7 million for the current year’s period, when compared to the prior year’s period, primarily due to our net income for the current period increasing by $5.6 million and from a $4.2 million increase in depreciation, depletion, amortization and accretion (primarily due to increased sales production, noted above), offset by a $4.2 million net loss on sale of oil and gas properties (primarily from a $4.3 million loss on the sale of our EOR Operating Company subsidiary and its corresponding assets in the prior period) and by a $16.3 million net decrease to our other components of working capital in the current period (due to increased cash payments and decreased payables and expenses outstanding from our drilling and completion activity) when comparing periods.
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| Table of Contents |
Cash used in investing activities. Net cash used in investing activities decreased by $8.9 million for the current year’s period, when compared to the prior year’s period, primarily due to decreased cash outlays from our capital spending relating to our drilling and completion activities.
Cash financing activities. There were no cash flow financing activities in the current or prior period.
Non-GAAP Financial Measures
We have included EBITDA and Adjusted EBITDA in this Report as supplements to generally accepted accounting principles in the United States of America (“GAAP”) measures of performance to provide investors with an additional financial analytical framework which management uses, in addition to historical operating results, as the basis for financial, operational and planning decisions and present measurements that third parties have indicated are useful in assessing the Company and its results of operations. “EBITDA” represents net income before interest, taxes, depreciation and amortization. “Adjusted EBITDA” represents EBITDA, less share-based compensation, loss on sale of oil and gas properties, net, and gain on sale of fixed assets. Adjusted EBITDA excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDA and Adjusted EBITDA are presented because we believe they provide additional useful information to investors due to the various noncash items during the period. EBITDA and Adjusted EBITDA are also frequently used by analysts, investors and other interested parties to evaluate companies in our industry. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA and Adjusted EBITDA do not reflect cash expenditures, future requirements for capital expenditures, or contractual commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and EBITDA and Adjusted EBITDA do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments. For example, although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Additionally, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than PEDEVCO Corp. does, limiting its usefulness as a comparative measure. You should not consider EBITDA and Adjusted EBITDA in isolation, or as substitutes for analysis of the Company’s results as reported under GAAP. The Company’s presentation of these measures should not be construed as an inference that future results will be unaffected by unusual or nonrecurring items. We compensate for these limitations by providing a reconciliation of each of these non-GAAP measures to the most comparable GAAP measure. We encourage investors and others to review our business, results of operations, and financial information in their entirety, not to rely on any single financial measure, and to view these non-GAAP measures in conjunction with the most directly comparable GAAP financial measure. The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDA (in thousands):
|
| Years Ended |
| |||||
|
| December 31, |
| |||||
|
|
|
|
| 2023 |
| ||
|
| 2024 |
|
| (As Restated) |
| ||
Net income |
| $ | 17,789 |
|
| $ | 1,699 |
|
Add (deduct) |
|
|
|
|
|
|
|
|
Income tax benefit |
|
| (12,751 | ) |
|
| - |
|
Depreciation, depletion, amortization and accretion |
|
| 15,920 |
|
|
| 9,440 |
|
EBITDA |
|
| 20,958 |
|
|
| 11,139 |
|
Add (deduct) |
|
|
|
|
|
|
|
|
Share-based compensation |
|
| 1,859 |
|
|
| 2,043 |
|
Loss on sale of oil and gas properties, net |
|
| 76 |
|
|
| 4,268 |
|
Gain on sale of fixed assets |
|
| (12 | ) |
|
| - |
|
Adjusted EBITDA |
| $ | 22,881 |
|
| $ | 17,450 |
|
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| Table of Contents |
Critical Accounting Estimates
Our discussion and analysis of our financial condition and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our most significant judgments and estimates used in preparation of our financial statements.
Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise, the related well costs are expensed as dry holes.
Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above.
Depreciation, depletion and amortization of capitalized oil and gas properties is calculated on a field-by-field basis using the unit of production method. Lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves and all other capitalized costs are amortized over proved developed reserves. Costs specific to developmental wells for which drilling is in progress or uncompleted are capitalized as wells in progress and not subject to amortization until completion and production commences, at which time amortization on the basis of production will begin.
Asset Retirement Obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the unit-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in DD&A expense in the Consolidated Statement of Operations.
Revenue Recognition. The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.
Contracts with customers have varying terms, including month-to-month contracts, and contracts with a finite term. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.
Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.
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| Table of Contents |
Stock-Based Compensation. Pursuant to the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 718, Compensation – Stock Compensation, which establishes accounting for equity instruments exchanged for employee service, we utilize the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. We estimate volatility by considering historical stock volatility. We have opted to use the simplified method for estimating expected term, which is equal to the midpoint between the vesting period and the contractual term.
Recently Adopted Accounting Pronouncements. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280). The amendments in this update expand segment disclosure requirements, including new segment disclosure requirements for entities with a single reportable segment among other disclosure requirements. This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Adoption of this standard is on a modified retrospective basis and had no impact on the Company’s financial position, results of operations, cash flows or net income per share.
Recently Issued Accounting Pronouncements. In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures. This ASU will be effective for the annual period ending December 31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
Not required under Regulation S-K for “smaller reporting companies.”
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
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| Table of Contents |
INDEX TO FINANCIAL STATEMENTS
Audited Financial Statements for Years Ended December 31, 2024 and 2023 |
|
|
|
PEDEVCO Corp.: |
|
Report of Independent Registered Public Accounting Firm (PCAOB ID Number | 86 |
Consolidated Balance Sheets as of December 31, 2024 and 2023 | 87 |
Consolidated Statements of Operations for the Years Ended December 31, 2024 and 2023 | 88 |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024 and 2023 | 89 |
90 | |
91 |
| 85 |
| Table of Contents |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of
PEDEVCO Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PEDEVCO Corp. (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of income (operations), changes in shareholders’ equity and cash flows for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America
Restatement of 2023 and 2022 Financial Statements
As discussed in Note 4 to the consolidated financial statements, the consolidated financial statements as of December 31, 2023 and 2022 and for the years ended December 31 2023 and 2022 have been restated to correct misstatements.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Proved Developed Oil Reserves on Proved Oil and Gas Properties, Net
As described in Notes 3 and 7 to the consolidated financial statements, a significant portion of the Company’s properties and equipment, net balance of $103.5 million as of December 31, 2024, and depreciation, depletion and amortization (“DD&A”) expense of $15.9 million for the year ended December 31, 2024 relate to proved oil and gas properties. The Company uses the successful efforts method of accounting for its oil and gas producing activities. As disclosed by management, the Company’s rate of recording DD&A expense is dependent upon the estimate of proved reserves and proved developed reserves, which are utilized in the unit-of-production calculation. In estimating proved oil and natural gas reserves, management relies on interpretations and judgment of available geological, geophysical, engineering and production data. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimates of oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.
The principal considerations for our determination that performing procedures relating to the impact of proved developed oil reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved developed oil reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved developed oil reserves.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved developed oil reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of the data used by the specialists, and evaluating the specialists’ findings.
/s/
Marcum llp
We have served as the Company’s auditor since 2008.
March 31, 2025
| 86 |
| Table of Contents |
PEDEVCO CORP.
CONSOLIDATED BALANCE SHEETS
(amounts in thousands, except share and per share data)
|
| December 31, |
| |||||
|
| 2024 |
|
| 2023 |
| ||
Assets |
|
|
|
| As Restated |
| ||
Current assets: |
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ |
|
| $ |
| ||
Accounts receivable – oil and gas |
|
|
|
|
|
| ||
Note receivable, current |
|
|
|
|
|
| ||
Prepaid expenses and other current assets |
|
|
|
|
|
| ||
Total current assets |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Oil and gas properties: |
|
|
|
|
|
|
|
|
Oil and gas properties, subject to amortization, net |
|
|
|
|
|
| ||
Oil and gas properties, not subject to amortization, net |
|
|
|
|
|
| ||
Total oil and gas properties, net |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Note receivable |
|
|
|
|
|
| ||
Operating lease – right-of-use asset |
|
|
|
|
|
| ||
Deferred income taxes |
|
|
|
|
|
| ||
Other assets |
|
|
|
|
|
| ||
Total assets |
| $ |
|
| $ |
| ||
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
| $ |
|
| $ |
| ||
Accrued expenses |
|
|
|
|
|
| ||
Revenue payable |
|
|
|
|
|
| ||
Operating lease liabilities – current |
|
|
|
|
|
| ||
Asset retirement obligations – current |
|
|
|
|
|
| ||
Total current liabilities |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Long-term liabilities: |
|
|
|
|
|
|
|
|
Operating lease liabilities, net of current portion |
|
|
|
|
|
| ||
Asset retirement obligations, net of current portion |
|
|
|
|
|
| ||
Total liabilities |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders’ equity: |
|
|
|
|
|
|
|
|
Common stock, $ |
|
|
|
|
|
| ||
Additional paid-in capital |
|
|
|
|
|
| ||
Accumulated deficit |
|
| ( | ) |
|
| ( | ) |
Total shareholders’ equity |
|
|
|
|
|
| ||
Total liabilities and shareholders’ equity |
| $ |
|
| $ |
| ||
See accompanying notes to consolidated financial statements.
| 87 |
| Table of Contents |
PEDEVCO CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(amounts in thousands, except share and per share data)
|
| December 31, |
| |||||
|
| 2024 |
|
| 2023 |
| ||
Revenue: |
|
|
| As Restated |
| |||
Oil and gas sales |
| $ |
|
| $ |
| ||
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
Lease operating costs |
|
|
|
|
|
| ||
Selling, general and administrative expense |
|
|
|
|
|
| ||
Depreciation, depletion, amortization and accretion |
|
|
|
|
|
| ||
Total operating expenses |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Loss on sale of oil and gas properties, net |
|
| ( | ) |
|
| ( | ) |
Operating income |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Other income (Expense): |
|
|
|
|
|
|
|
|
Interest income |
|
|
|
|
|
| ||
Gain on sale of fixed asset |
|
|
|
|
|
| ||
Other (expense) income |
|
| ( | ) |
|
|
| |
Total other income |
|
|
|
|
|
| ||
Income before income taxes |
|
|
|
|
|
| ||
Income tax benefit |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Net Income |
| $ |
|
| $ |
| ||
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
Basic |
| $ |
|
| $ |
| ||
Diluted |
| $ |
|
| $ |
| ||
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
| ||
Diluted |
|
|
|
|
|
| ||
See accompanying notes to consolidated financial statements.
| 88 |
| Table of Contents |
PEDEVCO CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)
|
| December 31, |
| |||||
|
| 2024 |
|
| 2023 |
| ||
|
|
|
| As Restated |
| |||
Cash Flows From Operating Activities: |
|
|
|
|
|
| ||
Net income |
| $ |
|
| $ |
| ||
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
|
|
|
| ||
Share-based compensation expense |
|
|
|
|
|
| ||
Loss on sale of oil and gas properties, net |
|
|
|
|
|
| ||
Gain on disposal of fixed asset |
|
| ( | ) |
|
|
| |
Uncollected account expense |
|
|
|
|
|
| ||
Amortization of right-of-use asset |
|
|
|
|
|
| ||
Deferred income tax benefit |
|
| ( | ) |
|
|
| |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable – oil and gas |
|
| ( | ) |
|
| ( | ) |
Note receivable |
|
| ( | ) |
|
| ( | ) |
Prepaid expenses and other current assets |
|
| ( | ) |
|
| ( | ) |
Accounts payable |
|
|
|
|
| ( | ) | |
Accrued expenses |
|
| ( | ) |
|
|
| |
Revenue payable |
|
| ( | ) |
|
|
| |
Net cash provided by operating activities |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities: |
|
|
|
|
|
|
|
|
Cash paid for drilling and completion costs |
|
| ( | ) |
|
| ( | ) |
Cash paid for other property and equipment |
|
| ( | ) |
|
| ( | ) |
Proceeds from the sale of oil and gas property |
|
|
|
|
|
| ||
Cash received for sale of vehicle |
|
|
|
|
|
| ||
Cash paid for issuance of note receivable |
|
|
|
|
| ( | ) | |
Cash received for security deposit |
|
|
|
|
|
| ||
Net cash used in investing activities |
|
| ( | ) |
|
| ( | ) |
|
|
|
|
|
|
|
|
|
Net decrease in cash and restricted cash |
|
| ( | ) |
|
| ( | ) |
Cash and restricted cash at beginning of year |
|
|
|
|
|
| ||
Cash and restricted cash at end of year |
| $ |
|
| $ |
| ||
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
|
|
Cash paid for: |
|
|
|
|
|
|
|
|
Interest |
| $ |
|
| $ |
| ||
Income taxes |
| $ |
|
| $ |
| ||
|
|
|
|
|
|
|
|
|
Noncash investing and financing activities: |
|
|
|
|
|
|
|
|
Change in accrued oil and gas development costs |
| $ |
|
| $ |
| ||
Change in estimates of asset retirement costs |
| $ |
|
| $ |
| ||
Issuance of restricted common stock |
| $ |
|
| $ |
| ||
See accompanying notes to consolidated financial statements.
| 89 |
| Table of Contents |
PEDEVCO CORP.
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
For the Years Ended December 31, 2024 and 2023
(amounts in thousands, except share amounts)
|
|
|
|
|
|
|
| Additional |
|
|
|
|
|
|
| |||||
|
| Common Stock |
|
| Paid-in |
|
| Accumulated |
|
|
|
| ||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| Deficit |
|
| Totals |
| |||||
|
|
|
|
|
|
|
| (As Restated) |
|
| (As Restated) |
| ||||||||
Balances at December 31, 2022 |
|
|
|
| $ |
|
| $ |
|
| $ | ( | ) |
| $ |
| ||||
Issuance of restricted common stock |
|
|
|
|
|
|
|
| ( | ) |
|
|
|
|
|
| ||||
Stock-based compensation |
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income |
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Balances at December 31, 2023 |
|
|
|
|
|
|
|
|
|
|
| ( | ) |
|
|
| ||||
Issuance of restricted common stock |
|
|
|
|
|
|
|
| ( | ) |
|
|
|
|
|
| ||||
Rescinded restricted common stock |
|
| ( | ) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Stock-based compensation |
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income |
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Balances at December 31, 2024 |
|
|
|
| $ |
|
| $ |
|
| $ | ( | ) |
| $ |
| ||||
See accompanying notes to consolidated financial statements.
| 90 |
| Table of Contents |
PEDEVCO CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – BASIS OF PRESENTATION
The accompanying consolidated financial statements of PEDEVCO Corp. (“PEDEVCO” or the “Company”), have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and the rules of the Securities and Exchange Commission (“SEC”).
The Company’s consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and subsidiaries in which the Company has a controlling financial interest. All significant inter-company accounts and transactions have been eliminated in consolidation.
NOTE 2 – DESCRIPTION OF BUSINESS
PEDEVCO is an oil and gas company focused on the development, acquisition and production of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, the Company focuses 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. The Company’s current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “Permian Basin”) and in the Denver-Julesberg Basin (“D-J Basin”) in Colorado and Wyoming. The Company holds its Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through its wholly-owned operating subsidiary, Pacific Energy Development Corp. (“PEDCO”), which asset the Company refers to as its “Permian Basin Asset,” and it holds its D-J Basin acres located in Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, through its wholly-owned subsidiary, PRH Holdings LLC, and which asset the Company refers to as its “D-J Basin Asset.” In 2023, the Company assigned all of its oil and gas assets held in its wholly-owned subsidiary Red Hawk Petroleum LLC to PRH Holdings LLC.
The Company believes that horizontal development and exploitation of conventional assets in the Permian Basin and development of the Wattenberg and Wattenberg Extension in the D-J Basin represent among the most economic oil and natural gas plays in the United States (“U.S.”). Moving forward, the Company plans to optimize its existing assets and opportunistically seek additional acreage proximate to its currently held core acreage, as well as other attractive onshore U.S. oil and gas assets that fit the Company’s acquisition criteria, that Company management believes can be developed using its technical and operating expertise and be accretive to shareholder value.
NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation.The consolidated financial statements herein have been prepared in accordance with GAAP and include the accounts of the Company and those of its wholly and partially-owned subsidiaries as follows: (i) PEDCO, a Nevada corporation; (ii) Red Hawk Petroleum LLC, a Nevada limited liability company; (iii) Ridgeway Arizona Oil Corp., an Arizona corporation (“RAZO”); (iv) SRPT Acquisition, LLC, a Texas limited liability company, and (v) PRH Holdings LLC, a Nevada limited liability company. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates in Financial Statement Preparation. The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates generally include those with respect to the amount of recoverable oil and gas reserves, the fair value of financial instruments, oil and gas depletion, asset retirement obligations, and stock-based compensation.
| 91 |
| Table of Contents |
Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. As of December 31, 2024 and 2023, cash equivalents consisted of money market funds and cash on deposit of $-
Concentrations of Credit Risk. Financial instruments which potentially subject the Company to concentrations of credit risk include cash deposits placed with financial institutions. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal.
Sales to three customers comprised
Accounts Receivable. Accounts receivable typically consist of oil and gas receivables. The Company has classified these as short-term assets in the balance sheet because the Company expects repayment or recovery within the next 12 months. The Company evaluates these accounts receivable for collectability considering the results of operations of these related entities and, when necessary, records allowances for expected unrecoverable amounts. To date, no allowances have been recorded. Included in accounts receivable – oil and gas are $
Bad Debt Expense. The Company’s ability to collect outstanding receivables is critical to its operating performance and cash flows. Accounts receivable are stated at an amount management expects to collect from outstanding balances. The Company extends credit in the normal course of business. The Company regularly reviews outstanding receivables and when the Company determines that a party may not be able to make required payments, a charge to bad debt expense in the period of determination is made. Though the Company’s bad debts have not historically been significant, the Company could experience increased bad debt expense should a financial downturn occur.
Equipment. Equipment is stated at cost less accumulated depreciation and amortization. Maintenance and repairs are charged to expense as incurred. Renewals and betterments which extend the life or improve existing equipment are capitalized. Upon disposition or retirement of equipment, the cost and related accumulated depreciation are removed, and any resulting gain or loss is reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of the assets, which are
Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise, the related well costs are expensed as dry holes.
Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above.
| 92 |
| Table of Contents |
Depreciation, depletion and amortization of capitalized oil and gas properties is calculated on a field-by-field basis using the unit of production method. Lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves and all other capitalized costs are amortized over proved developed reserves. Costs specific to developmental wells for which drilling is in progress or uncompleted are capitalized as wells in progress and not subject to amortization until completion and production commences, at which time amortization on the basis of production will begin.
Impairment of Long-Lived Assets. The Company reviews the carrying value of its long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value.
Asset Retirement Obligations. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company will record a liability (an asset retirement obligation or “ARO”) on its consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the capitalized costs are depreciated on a unit-of-production basis over the estimated proved developed reserves. Both the accretion and the depreciation will be included in depreciation, depletion and amortization expense on our consolidated statements of operations.
Revenue Recognition. The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.
Contracts with customers have varying terms, including month-to-month contracts, and contracts with a finite term. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.
Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.
Income Taxes. The Company utilizes the asset and liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carry-forwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the value of such assets will be realized.
| 93 |
| Table of Contents |
Uncertain Tax Positions. The Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained.
The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results.
Stock-Based Compensation. The Company utilizes the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances.
The Company estimates volatility by considering the historical stock volatility. The Company has opted to use the simplified method for estimating expected term, which is generally equal to the midpoint between the vesting period and the contractual term.
Earnings per Common Share. Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) available to common shareholders (numerator) by the weighted average number of shares outstanding (denominator) during the period. Diluted EPS give effect to all dilutive potential common shares outstanding during the period using the treasury stock method and convertible preferred stock using the if-converted method. In computing diluted EPS, the average stock price for the period is used to determine the number of shares assumed to be purchased from the exercise of stock options and/or warrants. Diluted EPS excluded all dilutive potential shares if their effect is anti-dilutive. For the year ended December 31, 2024, potentially dilutive securities related to options (
Recently Adopted Accounting Pronouncements. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280). The amendments in this update expand segment disclosure requirements, including new segment disclosure requirements for entities with a single reportable segment among other disclosure requirements. This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Adoption of this standard is on a modified retrospective basis and had no impact on the Company’s financial position, results of operations, cash flows or net income per share.
Recently Issued Accounting Pronouncements. In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures. This ASU will be effective for the annual period ending December 31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU
Subsequent Events. The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration.
| 94 |
| Table of Contents |
NOTE 4 – RESTATEMENT OF PREVIOUSLY ISSUED CONSOLIDATED FINANCIAL STATEMENTS
In connection with the preparation of the Company's Consolidated Financial Statements as of and for the fiscal year ended December 31, 2024, the Company discovered that in prior years it had not appropriately accounted for the depletion expense related to its oil and gas properties. The error resulted in an overstatement of depreciation, depletion, amortization and accretion expense and accumulated DD&A of approximately $
The misstatements were material to the previously issued financial statements of the Company and as a result, the Company has restated its Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Cash Flows, Consolidated Statements of Changes in Shareholder's Equity and for Note 7 – Oil and Gas Properties, Note 13 – Earnings Per Common Share and Note 14 – Income Taxes, and as of and for the fiscal years ended December 31, 2023 and 2022, respectively, presented herein. The restatement includes adjustments to oil and gas properties, subject to amortization, net; depreciation, depletion, amortization and accretion; accumulated deficit; net income; and earnings per share.
The impact of the correction of the misstatements is summarized below:
|
| As of December 31, 2023 |
| |||||||||
CORRECTED CONSOLIDATED BALANCE SHEETS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Oil and gas properties, subject to amortization, net |
| $ |
|
| $ |
|
| $ |
| |||
Total oil and gas properties, net |
|
|
|
|
|
|
|
|
| |||
Total assets |
|
|
|
|
|
|
|
|
| |||
Accumulated deficit |
|
| ( | ) |
|
|
|
|
| ( | ) | |
Total shareholders’ equity |
|
|
|
|
|
|
|
|
| |||
Total liabilities and shareholders’ equity |
|
|
|
|
|
|
|
|
| |||
|
| As of December 31, 2023 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF OPERATIONS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Depreciation, depletion, amortization and accretion |
| $ |
|
| $ | ( | ) |
| $ |
| ||
Total operating expenses |
|
|
|
|
| ( | ) |
|
|
| ||
Operating (loss) income |
|
| ( | ) |
|
|
|
|
|
| ||
Net Income |
|
|
|
|
|
|
|
|
| |||
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
|
|
|
| |||
Diluted |
|
|
|
|
|
|
|
|
| |||
| 95 |
| Table of Contents |
|
| As of December 31, 2023 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Cash Flows From Operating Activities: |
|
|
|
|
|
|
|
|
| |||
Net income |
| $ |
|
| $ |
|
| $ |
| |||
Depreciation, depletion and amortization |
|
|
|
|
| ( | ) |
|
|
| ||
Net cash used in operating activities |
|
|
|
|
|
|
|
|
| |||
|
| As of December 31, 2022 |
| |||||||||
CORRECTED CONSOLIDATED BALANCE SHEETS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Oil and gas properties, subject to amortization, net |
| $ |
|
| $ |
|
| $ |
| |||
Total oil and gas properties, net |
|
|
|
|
|
|
|
|
| |||
Total assets |
|
|
|
|
|
|
|
|
| |||
Accumulated deficit |
|
| ( | ) |
|
|
|
|
| ( | ) | |
Total shareholders’ equity |
|
|
|
|
|
|
|
|
| |||
Total liabilities and shareholders’ equity |
|
|
|
|
|
|
|
|
| |||
|
| As of December 31, 2022 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF OPERATIONS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Depreciation, depletion, amortization and accretion |
| $ |
|
| $ | ( | ) |
| $ |
| ||
Total operating expenses |
|
|
|
|
| ( | ) |
|
|
| ||
Operating (loss) income |
|
|
|
|
|
|
|
|
| |||
Net Income |
|
|
|
|
|
|
|
|
| |||
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
|
|
|
| |||
Diluted |
|
|
|
|
|
|
|
|
| |||
| 96 |
| Table of Contents |
|
| As of December 31, 2022 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Cash Flows From Operating Activities: |
|
|
|
|
|
|
|
|
| |||
Net income |
| $ |
|
|
|
|
| $ |
| |||
Depreciation, depletion and amortization |
|
|
|
|
| ( | ) |
|
|
| ||
|
| (Accumulated Deficit) |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Balances at December 31, 2022 |
| $ | ( | ) |
| $ |
|
| $ | ( | ) | |
Net income |
|
|
|
|
|
|
|
|
| |||
Balances at December 31, 2023 |
|
| ( | ) |
|
|
|
|
| ( | ) | |
|
| As of December 31, 2023 |
| |||||||||
CORRECTED CONSOLIDATED BALANCE SHEETS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Oil and gas properties, subject to amortization, net |
| $ | 79,186 |
|
| $ | 2,686 |
|
| $ | 81,872 |
|
Total oil and gas properties, net |
|
| 91,593 |
|
|
| 2,686 |
|
|
| 94,279 |
|
Total assets |
|
| 120,058 |
|
|
| 2,686 |
|
|
| 122,744 |
|
Accumulated deficit |
|
| (126,477 | ) |
|
| 2,686 |
|
|
| (123,791 | ) |
Total shareholders’ equity |
|
| 98,766 |
|
|
| 2,686 |
|
|
| 101,452 |
|
Total liabilities and shareholders’ equity |
|
| 120,058 |
|
|
| 2,686 |
|
|
| 122,744 |
|
| 97 |
| Table of Contents |
|
| As of December 31, 2023 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF OPERATIONS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Depreciation, depletion, amortization and accretion |
| $ | 10,875 |
|
| $ | (1,435 | ) |
| $ | 9,440 |
|
Total operating expenses |
|
| 26,714 |
|
|
| (1,435 | ) |
|
| 25,279 |
|
Operating (loss) income |
|
| (198 | ) |
|
| 1,435 |
|
|
| 1,237 |
|
Net Income |
|
| 264 |
|
|
| 1,435 |
|
|
| 1,699 |
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| 0.00 |
|
|
| 0.02 |
|
|
| 0.02 |
|
Diluted |
|
| 0.00 |
|
|
| 0.02 |
|
|
| 0.02 |
|
|
| As of December 31, 2023 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Cash Flows From Operating Activities: |
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 264 |
|
| $ | 1,435 |
|
| $ | 1,699 |
|
Depreciation, depletion and amortization |
|
| 10,875 |
|
|
| (1,435 | ) |
|
| 9,440 |
|
Net cash used in operating activities |
|
| 23,481 |
|
|
| - |
|
|
| 23,481 |
|
| 98 |
| Table of Contents |
|
| As of December 31, 2022 |
| |||||||||
CORRECTED CONSOLIDATED BALANCE SHEETS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Oil and gas properties, subject to amortization, net |
| $ | 79,372 |
|
| $ | 1,251 |
|
| $ | 80,623 |
|
Total oil and gas properties, net |
|
| 80,147 |
|
|
| 1,251 |
|
|
| 81,398 |
|
Total assets |
|
| 116,110 |
|
|
| 1,251 |
|
|
| 117,361 |
|
Accumulated deficit |
|
| (126,741 | ) |
|
| 1,251 |
|
|
| (125,490 | ) |
Total shareholders’ equity |
|
| 96,459 |
|
|
| 1,251 |
|
|
| 97,710 |
|
Total liabilities and shareholders’ equity |
|
| 116,110 |
|
|
| 1,251 |
|
|
| 117,361 |
|
|
| As of December 31, 2022 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF OPERATIONS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Depreciation, depletion, amortization and accretion |
| $ | 11,153 |
|
| $ | (1,251 | ) |
| $ | 9,902 |
|
Total operating expenses |
|
| 27,404 |
|
|
| (1,251 | ) |
|
| 26,153 |
|
Operating (loss) income |
|
| 2,630 |
|
|
| 1,251 |
|
|
| 3,881 |
|
Net Income |
|
| 2,844 |
|
|
| 1,251 |
|
|
| 4,095 |
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| 0.03 |
|
|
| 0.02 |
|
|
| 0.05 |
|
Diluted |
|
| 0.03 |
|
|
| 0.02 |
|
|
| 0.05 |
|
|
| As of December 31, 2022 |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Cash Flows From Operating Activities: |
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 2,844 |
|
|
| 1,251 |
|
| $ | 4,095 |
|
Depreciation, depletion and amortization |
|
| 11,153 |
|
|
| (1,251 | ) |
|
| 9,902 |
|
|
| (Accumulated Deficit) |
| |||||||||
CORRECTED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY |
| As previously reported |
|
| Impact of Adjustment |
|
| As Restated |
| |||
Balances at December 31, 2022 |
| $ | (126,741 | ) |
| $ | 1,251 |
|
| $ | (125,490 | ) |
Net income |
|
| 264 |
|
|
| 1,435 |
|
|
| 1,699 |
|
Balances at December 31, 2023 |
|
| (126,477 | ) |
|
| 2,686 |
|
|
| (123,791 | ) |
| 99 |
| Table of Contents |
NOTE 5 – CASH
The following table provides a reconciliation of cash and restricted cash reported within the balance sheets on December 31, 2024 and 2023, which sum to the total of such amounts shown in the accompanying consolidated statements of cash flows (in thousands):
|
| 2024 |
|
| 2023 |
| ||
Cash |
| $ |
|
| $ |
| ||
Restricted cash included in other assets* |
|
|
|
|
|
| ||
Total cash and restricted cash |
| $ |
|
| $ |
| ||
* Increase in restricted cash is primarily related to additional collateral for surety bonds for the Company’s New Mexico operations, due to an updated assessment from the New Mexico Bureau of Land Management.
NOTE 6 – REVENUE FROM CONTRACTS WITH CUSTOMERS
Disaggregation of Revenue from Contracts with Customers. The following table disaggregates revenue by significant product type for the years ended December 31, 2024 and 2023 (in thousands):
|
| 2024 |
|
| 2023 |
| ||
Oil sales |
| $ |
|
| $ |
| ||
Natural gas sales |
|
|
|
|
|
| ||
Natural gas liquids sales |
|
|
|
|
|
| ||
Total revenue from customers |
| $ |
|
| $ |
| ||
There were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of December 31, 2024 or 2023, respectively.
| 100 |
| Table of Contents |
NOTE 7 – OIL AND GAS PROPERTIES
The following tables summarize the Company’s oil and gas activities by classification for the years ended December 31, 2024 and 2023, respectively (in thousands):
|
| Balance at December 31, |
|
|
|
|
|
|
|
|
|
|
| Balance at December 31, |
| |||||
|
| 2023 |
|
| Additions |
|
| Disposals |
|
| Transfers |
|
| 2024 |
| |||||
|
| as Restated |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Oil and gas properties, subject to amortization |
| $ |
|
| $ |
|
| $ | ( | ) |
| $ |
|
| $ |
| ||||
Oil and gas properties, not subject to amortization |
|
|
|
|
|
|
|
|
|
|
| ( | ) |
|
|
| ||||
Asset retirement costs |
|
|
|
|
|
|
|
| ( | ) |
|
|
|
|
|
| ||||
Accumulated depreciation, depletion and impairment |
|
| ( | ) |
|
| ( | ) |
|
|
|
|
|
|
|
| ( | ) | ||
Total oil and gas assets |
| $ |
|
| $ |
|
| $ | ( | ) |
| $ |
|
| $ |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
| Balance at December 31, |
|
|
|
|
|
| Balance at December 31, |
| ||||||||||
|
| 2022 |
|
| Additions |
|
| Disposals |
|
| Transfers |
|
| 2023 |
| |||||
|
| as Restated |
|
|
|
|
|
|
|
|
|
|
| as Restated |
| |||||
Oil and gas properties, subject to amortization |
| $ |
|
| $ |
|
| $ | ( | ) |
| $ |
|
| $ | 185,403 |
| |||
Oil and gas properties, not subject to amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 12,407 |
| ||||
Asset retirement costs |
|
|
|
|
|
|
|
| ( | ) |
|
|
|
|
| 853 |
| |||
Accumulated depreciation, depletion and impairment (As Restated) |
|
| ( | ) |
|
| ( | ) |
|
|
|
|
|
|
|
| (104,384 | ) | ||
Total oil and gas assets (as Restated) |
| $ |
|
| $ |
|
| $ | ( | ) |
| $ |
|
| $ | 94,279 |
| |||
For the year ended December 31, 2024, the Company incurred $
As of December 31, 2024, the Company also acquired approximately 267 net mineral acres and 4,960 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 $
On August 21, 2024, the Company, through its wholly-owned subsidiary, PRH Holdings, LLC (“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”),
| 101 |
| Table of Contents |
Additionally, on September 23, 2024, PRH sold 320 net acres to a third-party in the Company’s D-J Basin Asset for $
For the year ended December 31, 2023, the Company incurred $
On September 12, 2023, the Company and Evolution entered into a Participation Agreement for the joint development of approximately 16,000 gross leasehold acres divided into twelve “Development Blocks” within the Company’s Permian Basin Asset, in which the parties may jointly develop by drilling and completion of up to nine horizontal San Andres wells in each Development Block. The Company received net proceeds of $
On November 9, 2023, the Company entered into a Purchase and Sale Agreement and a Stock Purchase Agreement with Tilloo, pursuant to which we sold our wholly-owned subsidiary EOR Operating Company (“EOR”) and approximately 8,035 gross leasehold acres, current operated production, and all of PEDCO’s and EOR’s leases and related rights, oil and gas and other wells, equipment, easements, contract rights, and production located in the Milnesand and Sawyer Fields of the San Andres play in the Permian Basin situated in eastern New Mexico, which assets included approximately 80 legacy vertical oil and gas wells (53 producers and 27 injectors). Aggregate consideration received by the Company for the sale, which was effective August 1, 2023, was $1,122,436, subject to customary adjustments, which is to be paid by Tilloo through entry into a five-year secured promissory note (see Note 7 below). As a result of the transaction, the Company sold all of its operated oil and gas interests in the non-core Milnesand and Sawyer Fields, including 52 inactive legacy wells that the Company would otherwise be required to plug and abandon, thereby successfully reducing its asset retirement obligations with respect to these assets and reducing its
The depletion recorded for production on proved properties for the year ended December 31, 2024 and 2023, amounted to $
NOTE 8 – NOTE RECEIVABLE
On November 9, 2023, in accordance with the sale of our wholly-owned subsidiary EOR to Tilloo (see Note 6 above), the Company entered into a five-year secured promissory note (the “Note”) with Tilloo, bearing interest at
| 102 |
| Table of Contents |
Tilloo failed to make the initial installment payment due under the Tilloo Note on January 8, 2025. The Company issued a notice of default under the Note to Tilloo in mid-January 2025, and the Company intends to pursue all available avenues and remedies, including potential foreclosure under the security agreement and mortgages securing the secured obligation, to resolve these matters. Tilloo may not timely pay the Note when due, if at all. However, as the Tilloo Note is fully-secured, the Company believes that should it pursue foreclosure under the security agreement and mortgages, that it would ultimately be made whole, so no reserve allowance is required as of December 31, 2024.
NOTE 9 – ASSET RETIREMENT OBLIGATION
Activity related to the Company’s asset retirement obligations is as follows for the year ended December 31, 2024 (in thousands):
|
| 2024 |
| |
Balance at the beginning of the period (1) |
| $ |
| |
Accretion expense |
|
|
| |
Disposition of liabilities |
|
| ( | ) |
Liabilities settled |
|
| ( | ) |
Changes in estimates |
|
|
| |
Balance at end of period (2) |
| $ |
| |
| (1) | Includes $ |
|
|
|
| (2) | Includes $ |
In New Mexico, the Company, through its New Mexico operating subsidiary RAZO, has entered into a Stipulated Final Order (“SFO”) 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 $
NOTE 10 – COMMITMENTS AND CONTINGENCIES
Lease Agreements
Currently, the Company has one operating sublease for office space that requires Accounting Standards Codification (“ASC”) Topic 842 treatment, discussed below.
The Company’s leases typically do not provide an implicit rate. Accordingly, the Company is required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at the commencement date. The Company’s incremental borrowing rate would reflect the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. However, the Company currently maintains no debt, and in order to apply an appropriate discount rate, the Company used a borrowing rate obtained from a financial institution at which it maintains banking accounts.
The Company had a lease for its corporate offices in Houston, Texas on approximately 5,200 square feet of office space that expired on
| 103 |
| Table of Contents |
Supplemental cash flow information related to the Company’s operating lease is included in the table below (in thousands):
|
| Year Ended |
| |
|
| December 31, 2024 |
| |
Cash paid for amounts included in the measurement of lease liabilities |
| $ |
| |
Supplemental balance sheet information related to operating leases is included in the table below (in thousands):
|
| December 31, 2024 |
| |
Operating lease – right-of-use asset |
| $ |
| |
|
|
|
|
|
Operating lease liabilities – current |
| $ |
| |
Operating lease liabilities – long-term |
|
|
| |
Total lease liability |
| $ |
| |
The weighted-average remaining lease term for the Company’s operating lease is
Lease liability with enforceable contract terms that have greater than one-year terms are as follows (in thousands):
2025 |
| $ |
| |
2026 |
|
|
| |
2027 |
|
|
| |
Thereafter |
|
|
| |
Total lease payments |
|
|
| |
Less imputed interest |
|
| ( | ) |
Total lease liability |
| $ |
|
Leasehold Drilling Commitments
The Company’s oil and gas leasehold acreage is subject to expiration of leases if the Company does not drill and hold such acreage by production or otherwise exercises options to extend such leases, if available, in exchange for payment of additional cash consideration.
Other Commitments
Although the Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Company is not currently a party to any material legal proceeding. In addition, the Company is not aware of any material legal or governmental proceedings against it or contemplated to be brought against it.
| 104 |
| Table of Contents |
As part of its regular operations, the Company may become party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its commercial operations, products, employees and other matters.
Although the Company provides no assurance about the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have on the Company, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the Company’s financial condition or results of operations.
Milnesand Sale Dispute and Tilloo Note Default
On November 4, 2024 the Company received correspondence from legal counsel to Tilloo Exploration & Production, LLC (“Tilloo”) seeking to recover damages which Tilloo is alleging were caused by alleged intentional misrepresentations made by principals of the Company to principals of Tilloo in connection with Tilloo’s acquisition of the Milnesand and Sawyer fields in New Mexico from the Company for aggregate consideration of $
NOTE 11 – SHAREHOLDERS’ EQUITY
Common Stock
During the year ended December 31, 2024, the Company granted an aggregate of
During the year ended December 31, 2023, the Company granted an aggregate of
NOTE 12 – SHARE-BASED COMPENSATION
2021 Incentive Plan
On September 1, 2021, the shareholders of the Company approved the 2021 Equity Incentive Plan (the “2021 Plan”), which was previously approved by the Board of Directors on July 11, 2021 and authorizes the issuance of various forms of stock-based awards, including incentive or non-qualified options, restricted stock awards, performance shares and other securities as described in greater detail in the 2021 Incentive Plan, to the Company’s employees, officers, directors and consultants. The 2021 Incentive Plan was amended on August 29, 2024 to increase the number of shares reserved for issuance under the 2021 Incentive Plan by 5,000,000 to
2012 Incentive Plan
On July 27, 2012, the shareholders of the Company approved the 2012 Equity Incentive Plan (the “2012 Incentive Plan”), which was previously approved by the Board of Directors on June 27, 2012 and authorizes the issuance of various forms of stock-based awards, including incentive or non-qualified options, restricted stock awards, performance shares and other securities as described in greater detail in the 2012 Incentive Plan, to the Company’s employees, officers, directors and consultants. The 2012 Incentive Plan was amended on June 27, 2014, October 7, 2015 and December 28, 2016, December 28, 2017, September 27, 2018 and August 28, 2019 to increase by
| 105 |
| Table of Contents |
Common Stock
On January 26, 2024, restricted stock awards were granted to officers and employees of the Company for an aggregate of
On August 29, 2024, an aggregate of
On May 24, 2024, 70,000 shares of restricted common stock were forfeited due to an employee termination. As a result, these shares were canceled, and the shares once again became eligible for future awards under the Company’s 2021 Plan.
On January 23, 2023, an aggregate of
On August 31, 2023, an aggregate of
The awarded shares above are subject to trading restrictions, and forfeiture, subject to the vesting terms described above. When such securities are vested in accordance with their terms, the trading restrictions are lifted.
Stock-based compensation expense recorded related to restricted stock during the years ended December 31, 2024 and 2023 was $
| 106 |
| Table of Contents |
Options
On January 26, 2024, the Company granted options to purchase an aggregate of
During the period ended December 31, 2024,
On January 23, 2023, the Company granted options to purchase an aggregate of
During the period ended December 31, 2023,
During the year ended December 31, 2024 and 2023, the Company recognized stock option-based compensation expense related to options of $
The remaining amount of unamortized stock options expense at December 31, 2024 and 2023 was $
There was no intrinsic value of outstanding and exercisable options at December 31, 2024 and 2023, respectively.
Option activity during the years ended December 31, 2024 and 2023 was:
|
| 2024 |
|
| 2023 |
| ||||||||||||||||||
|
| Number of Stock Options |
|
| Weighted Average Grant Price |
|
| Weighted Average Remaining Contract Term (Years) |
|
| Number of Stock Options |
|
| Weighted Average Grant Price |
|
| Weighted Average Remaining Contract Term (Years) |
| ||||||
Outstanding at Beginning of Period |
|
|
|
| $ |
|
|
|
|
|
|
|
| $ |
|
|
|
| ||||||
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Expired/Canceled |
|
| ( | ) |
|
|
|
|
|
|
|
|
| ( | ) |
|
|
|
|
|
|
| ||
Outstanding at End of Period |
|
|
|
| $ |
|
|
|
|
|
|
|
| $ |
|
|
|
| ||||||
Exercisable at End of Period |
|
|
|
| $ |
|
|
|
|
|
|
|
| $ |
|
|
|
| ||||||
| 107 |
| Table of Contents |
NOTE 13 – EARNINGS PER COMMON SHARE
Earnings per common share-basic is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. Net income per common share-diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income per common share-diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect.
The calculation of earnings per share for the years ended December 31, 2024 and December 31, 2023 were as follows (amounts in thousands, except share and per share data):
|
| 2024 |
|
| 2023 |
| ||
Numerator: |
|
|
| (As Restated) |
| |||
Net income |
| $ |
|
| $ |
| ||
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Weighted average common shares – basic |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Dilutive effect of common stock equivalents: |
|
|
|
|
|
|
|
|
Options |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Weighted average common shares – diluted |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Earnings per share – basic |
| $ |
|
| $ |
| ||
Earnings per share – diluted |
| $ |
|
| $ |
| ||
For the years ended December 31, 2024 and 2023, share equivalents related to options to purchase
NOTE 14 – INCOME TAXES
In conjunction with the restatement for DD&A, we also restated certain balances in the net deferred tax asset / deferred tax liability schedule to correct an additional error. The components of the income tax expense (benefit) for the years ended December 31, 2024, and 2023, respectively, are as follows:
|
| 2024 |
|
| 2023 |
| ||
|
|
|
|
| (As Restated) |
| ||
Current: |
|
|
|
|
|
| ||
Federal |
|
|
|
|
|
| ||
State |
|
|
|
|
|
| ||
Total current expense/(benefit) |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
Federal |
|
| ( | ) |
|
|
| |
State |
|
| ( | ) |
|
|
| |
Total deferred tax expense/(benefit) |
|
| ( | ) |
|
|
| |
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
| ( | ) |
|
|
| |
| 108 |
| Table of Contents |
The income tax expense (benefit) reported in our consolidated statement of operations is different from the federal income tax expense (benefit) computed using the federal statutory rate. The following table reconciles the U.S. federal statutory income tax rate in effect for the years ended December 31, 2024, and December 31, 2023 (in thousands):
|
| 2024 |
|
| 2023 |
| ||
|
|
|
|
| (As Restated) |
| ||
Statutory expense/(benefit) |
|
|
|
|
|
| ||
State tax, net |
|
|
|
|
|
| ||
Permanent differences |
|
|
|
|
|
| ||
Other adjustments |
|
|
|
|
|
| ||
Change in valuation allowance |
|
| ( | ) |
|
| ( | ) |
Income tax expense (benefit) |
|
| ( | ) |
|
|
| |
In 2024, the Company recorded a $
Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences and net operating loss (“NOL”) carryforwards that comprise our deferred income as of December 31, 2024, and 2023 taxes are as follows (in thousands):
|
| 2024 |
|
| 2023 |
| ||
|
|
|
|
| (As Restated) |
| ||
Deferred tax asset: |
|
|
|
|
|
| ||
Net operating losses |
|
|
|
|
|
| ||
Asset retirement obligations |
|
|
|
|
|
| ||
Stock compensation |
|
|
|
|
|
| ||
Right of use liability |
|
|
|
|
|
| ||
Other |
|
|
|
|
|
| ||
Deferred tax asset |
|
|
|
|
|
| ||
Valuation allowance |
|
|
|
|
| ( | ) | |
Deferred tax asset after valuation allowance |
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Oil and gas properties |
|
| ( | ) |
|
| ( | ) |
Right of use asset |
|
| ( | ) |
|
| ( | ) |
Deferred tax liability |
|
| ( | ) |
|
| ( | ) |
|
|
|
|
|
|
|
|
|
Net deferred tax asset / deferred tax liability |
|
|
|
|
|
| ||
As of December 31, 2024, and 2023, the Company had deferred tax assets of $
As of December 31, 2024, the Company has federal net operating loss carryforwards of approximately $
In assessing the realization of deferred tax assets, the Company considers whether it is more likely than not that some portion or all deferred assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
Utilization of NOL and tax credit carryforwards may be subject to a substantial annual limitation due to ownership change limitations that may have occurred or that could occur in the future, as required by the Internal Revenue Code (the “Code”), as amended, as well as similar state provisions. In general, an “ownership change” as defined by the Code results from a transaction or series of transactions over a three-year period resulting in an ownership change of more than 50 percent of the outstanding stock of a company by certain shareholders or public groups.
Based on the available objective evidence, the Company believes it is more likely than not that the net deferred tax assets will be fully realizable based on the Company's ability to generate income in future periods. Accordingly, the Company has recorded no valuation allowance against its net deferred tax assets on December 31, 2024.
The Company’s policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of December 31, 2024, and 2023, the Company did not have any significant uncertain tax positions or unrecognized tax benefits. The Company did not have associated accrued interest or penalties, nor was any interest expense or penalties recognized for the years ended December 31, 2023, and 2022.
The Company currently has tax returns open for examination by the Internal Revenue Service for all years, since 2019.
| 109 |
| Table of Contents |
NOTE 15 — SEGMENT INFORMATION
Operating segments are defined as components of an enterprise for which separate financial information is available and regularly evaluated by the Chief Operating Decision Maker (“CODM”) for the purpose of making key operating decisions, allocating resources, and assessing operating performance. The Company operates in one reportable operating segment, oil and natural gas development, exploration and production. The Company’s oil and gas properties are managed as a whole rather than through discrete operating segments. Financial and operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company’s entire portfolio without regard to geographic area, and considers among other things, return on investment, current market conditions, including commodity prices and market supply, availability of services and human resources, and contractual commitments. The Company’s Chief Executive Officer is its CODM.
The Company’s profitability measure is consolidated net income which is used to assess budgeted versus actual results and drives the Company’s operating cash flow. The CODM reviews significant consolidated forecasts and results of operations, including return on capital, operating expenses, and cash flow when making decisions such as the allocation of capital. The financial position, results of operations and cash flows of the Company’s reportable operating segment are consistent with the Company’s consolidated financial statements included herein.
NOTE 16 – SUBSEQUENT EVENTS
On January 23, 2025, the Company granted options to purchase an aggregate of
Additionally, on January 23, 2025, restricted stock awards were granted to officers and employees of the Company for an aggregate of
In addition, on January 23, 2025, after recommendation by the Compensation Committee of the Company’s Board of Directors, the Board of Directors of the Company, in connection with the Company’s annual compensation review, approved cash bonuses for
In February 2025, the Company entered into a joint development agreement (“Agreement”) with a large, Denver, Colorado-based private equity-backed D-J Basin E&P Company with extensive operational experience (“Operator”), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company’s Roth and Amber DSUs located in Weld County, Colorado, with the Operator paying to the Company $
| 110 |
| Table of Contents |
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
The following disclosures for the Company are made in accordance with authoritative guidance regarding disclosures about oil and natural gas producing activities. Users of this information should be aware that the process of estimating quantities of “proved,” “proved developed,” and “proved undeveloped” crude oil, natural gas liquids and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
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 developed reserves. Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
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.
PROVED RESERVE SUMMARY
All of the Company’s reserves are located in the United States. The following tables sets forth the changes in the Company’s net proved reserves (including developed and undeveloped reserves) for the years ended December 31, 2024 and 2023. Reserves estimates as of December 31, 2024 were estimated by the independent petroleum consulting firm Cawley, Gillespie & Associates, Inc. The reserve report is incorporated herein by reference to Exhibit 99.1 of the Annual Report on Form 10-K which these financial statements are filed with.
|
| December 31, |
| |||||
|
| 2024 |
|
| 2023 |
| ||
Crude Oil (MBbls) |
|
|
|
|
|
| ||
Net proved reserves at beginning of year |
|
| 11,358 |
|
|
| 11,611 |
|
Revisions of previous estimates |
|
| (2,638 | ) |
|
| 506 |
|
Purchases in place |
|
| 2,566 |
|
|
| - |
|
Extensions, discoveries and other additions |
|
| - |
|
|
| - |
|
Sales in place |
|
| (54 | ) |
|
| (384 | ) |
Production |
|
| (439 | ) |
|
| (375 | ) |
Net proved reserves at end of year |
|
| 10,793 |
|
|
| 11,358 |
|
|
|
|
|
|
|
|
|
|
Natural Gas (Mmcf) |
|
|
|
|
|
|
|
|
Net proved reserves at beginning of year |
|
| 19,885 |
|
|
| 16,379 |
|
Revisions of previous estimates |
|
| (2,090 | ) |
|
| 4,260 |
|
Purchases in place |
|
| 6,281 |
|
|
| - |
|
Extensions, discoveries and other additions |
|
| - |
|
|
| - |
|
Sales in place |
|
| (154 | ) |
|
| (323 | ) |
Production |
|
| (506 | ) |
|
| (431 | ) |
Net proved reserves at end of year |
|
| 23,416 |
|
|
| 19,885 |
|
|
|
|
|
|
|
|
|
|
NGL (MBbbls) |
|
|
|
|
|
|
|
|
Net proved reserves at beginning of year |
|
| 2,374 |
|
|
| 1,796 |
|
Revisions of previous estimates |
|
| 225 |
|
|
| 630 |
|
Purchases in place |
|
| 929 |
|
|
| - |
|
Extensions, discoveries and other additions |
|
| - |
|
|
| - |
|
Sales in place |
|
| (62 | ) |
|
| - |
|
Production |
|
| (19 | ) |
|
| (52 | ) |
Net proved reserves at end of year |
|
| 3,447 |
|
|
| 2,374 |
|
|
|
|
|
|
|
|
|
|
Oil Equivalents (MBoe) |
|
|
|
|
|
|
|
|
Net proved reserves at beginning of year |
|
| 17,046 |
|
|
| 16,137 |
|
Revisions of previous estimates |
|
| (2,762 | ) |
|
| 1,846 |
|
Purchases in place |
|
| 4,542 |
|
|
| - |
|
Extensions, discoveries and other additions |
|
| - |
|
|
| - |
|
Sales in place |
|
| (142 | ) |
|
| (438 | ) |
Production |
|
| (542 | ) |
|
| (499 | ) |
Net proved reserves at end of year |
|
| 18,142 |
|
|
| 17,046 |
|
| 111 |
| Table of Contents |
RESERVES
During the year ended December 31, 2024, the Company’s reserves increased by 1.1 MMBoe of proved reserves. Included in the increase, the Company had a 0.95 MMBoe increase in proved undeveloped reserves (noted below) resulting primarily from the addition of volumes in the D-J Basin due to increased activity. The Company also had an increase of 1.2 MMBoe in proved developed producing reserves related to acquisition of properties in the D-J Basin and reclassification of wells from proved developed non-producing at the end of 2023 to proved developed producing for 2024, which offset the natural decline in existing production base in the D-J Basin Asset and Permian Basin.
The following table sets forth the Company’s proved developed and undeveloped reserves at December 31, 2024 and 2023, respectively:
|
| 2024 |
|
| 2023 |
| ||
Proved Developed Reserves |
|
|
|
|
|
| ||
Crude Oil (MBbls) |
|
| 2,443 |
|
|
| 1,869 |
|
Natural Gas (Mmcf) |
|
| 4,292 |
|
|
| 2,998 |
|
NGL (MBbls) |
|
| 630 |
|
|
| 255 |
|
Oil Equivalents (MMBoe) |
|
| 3,788 |
|
|
| 2,624 |
|
|
|
|
|
|
|
|
|
|
Proved Developed Non-Producing Reserves |
|
|
|
|
|
|
|
|
Crude Oil (MBbls) |
|
| 13 |
|
|
| 702 |
|
Natural Gas (Mmcf) |
|
| 44 |
|
|
| 1,229 |
|
NGL (MBbls) |
|
| 7 |
|
|
| 144 |
|
Oil Equivalents (MMBoe) |
|
| 1,051 |
|
|
| 1,051 |
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
Crude Oil (MBbls) |
|
| 8,337 |
|
|
| 8,787 |
|
Natural Gas (Mmcf) |
|
| 19,079 |
|
|
| 15,659 |
|
NGL (MBbls) |
|
| 2,809 |
|
|
| 1,975 |
|
Oil Equivalents (MMBoe) |
|
| 14,327 |
|
|
| 13,372 |
|
|
|
|
|
|
|
|
|
|
Proved Reserves |
|
|
|
|
|
|
|
|
Crude Oil (MBbls) |
|
| 10,793 |
|
|
| 11,358 |
|
Natural Gas (Mmcf) |
|
| 23,415 |
|
|
| 19,886 |
|
NGL (MBbls) |
|
| 3,446 |
|
|
| 2,374 |
|
Oil Equivalents (MMBoe) |
|
| 18,142 |
|
|
| 17,046 |
|
| 112 |
| Table of Contents |
Proved Undeveloped Reserves
The following table is a reconciliation of the change in our PUD reserves for the periods indicated below (quantities in net MBoe):
Proved undeveloped reserves, December 31, 2022 |
|
| 12,942 |
|
Transfers to proved developed |
|
| (809 | ) |
Additions |
|
| 3,592 |
|
Revisions of prior estimates |
|
| (2,353 | ) |
Proved undeveloped reserves, December 31, 2023 |
|
| 13,372 |
|
Transfers to proved developed |
|
| -- |
|
Additions |
|
| 3,796 |
|
Revisions of prior estimates |
|
| (2,841 | ) |
Proved undeveloped reserves, December 31, 2024 |
|
| 14,327 |
|
For the year ended December 31, 2023, total proved undeveloped reserves (PUDs) increased by 430 MBoe to 13,372 MBoe, primarily related to the following:
| · | Transfer of 809 MBoe from PUD to proved developed reserves in D-J Basin (561 MBoe) and Permian Basin Asset (248 MBoe) based on total capital expenditures during 2023; |
|
|
|
| · | Additions of 3,592 MBoe related to the development of operated and non-operated sections in the D-J Basin (2,968 MBoe) and operated sections in Permian Basin (624 MBoe); and |
|
|
|
| · | Revisions related to increase in leasehold and minerals and expected performance increase of 1,447 MBoe in the D-J Basin Asset based on offset well results, and decrease of 3,311 MBoe related to removal of PUD locations in Chaveroo of our Permian Basin Asset outside of the five-year development plan and decrease of 489 Mboe primarily related to reduced working interest in a recently developed unit. |
For the year ended December 31, 2024, total proved undeveloped reserves (PUDs) increased by 955 MBoe to 14,327 MBoe, primarily related to the following:
| · | Additions of 3,796 MBoe related to the development of operated and non-operated sections in the D-J Basin (3,256 MBoe) and operated sections in Permian Basin (540 MBoe); and |
|
|
|
| · | Revisions of 2,841 Mboe related to increase in leasehold and minerals and expected performance increase of 586 MBoe in the D-J Basin Asset based on offset well results, and decrease of 3,427 MBoe related to removal of PUD locations in D-J Basin (1970 Mboe) and Chaveroo of our Permian Basin Asset (1457 MBoe) outside of the five-year development plan. |
|
|
|
| · | There was no transfer of proved undeveloped to proved developed reserves in 2024 since projects scheduled to be completed in 2024 were delayed to future periods and replaced with participation in wells through acquired leasehold properties in the D-J Basin. |
We expect to spend an aggregate of $170–$200 million developing proved undeveloped reserves through December 31, 2028. All proved undeveloped reserves are scheduled to be developed within five years of initial booking. We expect to fund these development costs with cash from operations and cash on hand, supplemented as needed by proceeds from asset sales, private and public offerings, credit availability and equity infusions or loans (which may be convertible) made available from Dr. Simon G. Kukes, the Company’s former Chief Executive Officer and newly appointed Executive Chairman of the Company's Board of Directors, or entities which he controls, which funding Dr. Kukes is under no obligation to provide.
| 113 |
| Table of Contents |
Capitalized Costs Relating to Oil and Natural Gas Producing Activities. The following table sets forth the capitalized costs relating to the Company’s crude oil and natural gas producing activities at December 31, 2024 and 2023 (in thousands):
|
| 2024 |
|
| 2023 |
| ||
|
|
|
| (As Restated) |
| |||
Proved oil and gas properties |
| $ | 222,807 |
|
| $ | 198,663 |
|
Unproved oil and gas properties |
|
| - |
|
|
| - |
|
Total oil & gas properties |
|
| 222,807 |
|
|
| 198,663 |
|
Accumulated depreciation and depletion and impairment |
|
| (119,295 | ) |
|
| (104,384 | ) |
Net Capitalized Costs |
| $ | 103,512 |
|
| $ | 94,279 |
|
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities. The following table sets forth the costs incurred in the Company’s oil and natural gas property acquisition, exploration and development activities for the years ended December 31, 2024 and 2023 (in thousands):
|
| 2024 |
|
| 2023 |
| ||
Acquisition of properties |
|
|
|
|
|
| ||
Proved |
| $ | 1,587 |
|
| $ | 5,704 |
|
Unproved |
|
| - |
|
|
| - |
|
Exploration costs |
|
| - |
|
|
| - |
|
Development costs |
|
| 20,522 |
|
|
| 21,523 |
|
Total |
| $ | 22,109 |
|
| $ | 27,227 |
|
Results of Operations for Oil and Natural Gas Producing Activities. The following table sets forth the results of operations for oil and natural gas producing activities for the years ended December 31, 2024 and 2023 (in thousands):
|
| 2024 |
|
| 2023 |
| ||
|
|
|
| (As Restated) |
| |||
Crude oil and natural gas revenues |
| $ | 39,553 |
|
| $ | 30,784 |
|
Production costs |
|
| (12,469 | ) |
|
| (9,831 | ) |
Depreciation and depletion and impairment |
|
| (14,911 | ) |
|
| (8,830 | ) |
Results of operations for producing activities, excluding corporate overhead and interest costs |
| $ | 12,173 |
|
| $ | 12,123 |
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves. The following information has been developed utilizing procedures prescribed by ASC Topic 932 and based on crude oil and natural gas reserves and production volumes estimated by the independent petroleum consultants of the Company. The estimates were based on a 12-month average of first-of-the-month commodity prices for the years ended December 31, 2024 and 2023. The following information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The future cash flows presented below are based on cost rates and statutory income tax rates in existence as of the date of the projections and average prices over the preceding twelve months. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
| 114 |
| Table of Contents |
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves as of December 31, 2024 and 2023 (in thousands):
|
| 2024 |
|
| 2023 |
| ||
Future cash inflows |
| $ | 916,105 |
|
| $ | 972,432 |
|
Future production costs |
|
| (288,879 | ) |
|
| (250,681 | ) |
Future development costs |
|
| (209,139 | ) |
|
| (202,842 | ) |
Future income taxes |
|
| (100,484 | ) |
|
| (121,204 | ) |
Future net cash flows |
|
| 317,603 |
|
|
| 397,705 |
|
Discount to present value at 10% annual rate |
|
| (173,440 | ) |
|
| (207,344 | ) |
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves |
| $ | 144,163 |
|
| $ | 190,361 |
|
Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows for each of the years ended December 31, 2024 and 2023 (in thousands):
|
| 2024 |
|
| 2023 |
| ||
Standardized measure, beginning of year |
| $ | 190,361 |
|
| $ | 274,916 |
|
Crude oil and natural gas sales, net of production costs |
|
| (24,653 | ) |
|
| (22,779 | ) |
Net changes in prices and production costs |
|
| (32,032 | ) |
|
| (76,156 | ) |
Extensions, discoveries, additions and improved recovery |
|
| - |
|
|
| - |
|
Changes in estimated future development costs |
|
| (740 | ) |
|
| (7,068 | ) |
Development costs incurred |
|
| - |
|
|
| - |
|
Revisions of previous quantity estimates |
|
| (40,363 | ) |
|
| (15,021 | ) |
Accretion of discount |
|
| (1,173 | ) |
|
| (11,697 | ) |
Net change in income taxes |
|
| 6,629 |
|
|
| 58,301 |
|
Purchases of reserves in place |
|
| 47,162 |
|
|
| - |
|
Sales of reserves in place |
|
| (1,028 | ) |
|
| (10,151 | ) |
Change in timing of estimated future production |
|
| - |
|
|
| 16 |
|
Standardized measure, end of year |
| $ | 144,163 |
|
| $ | 190,361 |
|
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
Disclosure Controls and Procedures
Disclosure controls and procedures are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time period specified in the SEC’s rules and forms and is accumulated and communicated to the Company’s management, as appropriate, in order to allow timely decisions in connection with required disclosure.
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”)(J. Douglas Schick) and Chief Accounting Officer (“CAO”), we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of December 31, 2024, the end of the period covered by this Annual Report. Based on this evaluation, our CEO and CAO concluded as of December 31, 2024, that our disclosure controls and procedures were not designed at a reasonable assurance level and were not effective to provide reasonable assurance that the information we are required to disclose in reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP, but because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. The Company’s internal control over financial reporting includes those policies and procedures that are designed to:
| ● | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; |
|
|
|
| ● | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and |
|
|
|
| ● | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. |
Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control— Integrated Framework (2013). Through the course of the Company’s preparation of its year-ended December 31, 2024 financial statements, a material weakness in our internal control over financial reporting was identified which 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 inclusion of all production for the current year in the reserve base for our calculation of depreciation, depletion, and amortization of our reserves. There was also a material weakness in the preparation of the tax provision. 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.
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Based on our assessment, management has concluded that the Company’s internal control over financial reporting were not effective as of December 31, 2024.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal controls over financial reporting during the quarter ended December 31, 2024 that have materially affected or are reasonably likely to materially affect, our internal controls over financial reporting, including any corrective actions with regard to significant deficiencies and material weaknesses, outside of the changes discussed above.
Limitations on the Effectiveness of Controls
The Company’s disclosure controls and procedures are designed to provide the Company’s Chief Executive Officer and Chief Accounting Officer with reasonable assurances that the Company’s disclosure controls and procedures will achieve their objectives. However, the Company’s management does not expect that the Company’s disclosure controls and procedures or the Company’s internal control over financial reporting can or will prevent all human error. A control system, no matter how well designed and implemented, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Furthermore, the design of a control system must reflect the fact that there are internal resource constraints, and the benefit of controls must be weighed relative to their corresponding costs. Because of the limitations in all control systems, no evaluation of controls can provide complete assurance that all control issues and instances of error, if any, within the Company’s company are detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur due to human error or mistake. Additionally, controls, no matter how well designed, could be circumvented by the individual acts of specific persons within the organization. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated objectives under all potential future conditions.
Attestation Report of the Registered Public Accounting Firm
This report does not include an attestation report of our registered public accounting firm regarding our internal controls over financial reporting. Under SEC rules, such attestation is not required for smaller reporting companies such as the Company.
ITEM 9B. OTHER INFORMATION.
(b) Rule 10b5-1 Trading Plans. During the quarter ended December 31, 2024, none of the Company’s directors or officers (as defined in Rule 16a-1(f)) adopted or terminated any contract, instruction or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any “non-Rule 10b5-1 trading arrangement.”
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.
Not applicable.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information about our Executive Officers and Directors
The following table sets forth the name, age and position held by each of our executive officers and directors. Directors are elected for a period of one year and thereafter serve until the next annual meeting at which their successors are duly elected by the shareholders or until such director’s resignation or removal.
Name |
| Age |
| Position |
|
|
|
|
|
Dr. Simon G. Kukes |
| 78 |
| Executive Chairman of the Company's Board of Directors (1) |
J. Douglas Schick |
| 49 |
| President and Chief Executive Officer and Director (2) |
Paul Pinkston |
| 57 |
| Chief Accounting Officer |
Clark R. Moore |
| 52 |
| Executive Vice President, General Counsel and Secretary |
Jody D. Crook |
| 48 |
| Chief Commercial Officer (3) |
John J. Scelfo |
| 67 |
| Director (4) |
H. Douglas Evans |
| 76 |
| Director (5) |
| (1) | Appointed Executive Chairman effective January 1, 2025; previously Chief Executive Officer through December 31, 2024. Has served as a member of the Board of Directors since July 2018. |
| (2) | Appointed as President, Chief Executive Officer and Director effective January 1, 2025; previously solely President through December 31, 2024. Has served as a member of the Board of Directors since January 2025. |
| (3) | Appointed Chief Commercial Officer effective January 1, 2025. |
| (4) | Previously Chairman of the Board through December 31, 2025. Has served as a member of the Board of Directors since July 2018. |
| (5) | Has served as a member of the Board of Directors since September 2018. |
There is no arrangement or understanding between our directors and executive officers and any other person pursuant to which any director or officer was or is to be selected as a director or officer, and there is no arrangement, plan or understanding as to whether non-management shareholders will exercise their voting rights to continue to elect the current Board of Directors (the “Board”). There are also no arrangements, agreements or understandings to our knowledge between non-management shareholders that may directly or indirectly participate in or influence the management of our affairs.
Business Experience
The following is a brief description of the business experience and background of our current directors and executive officers. There are no family relationships among any of the directors or executive officers.
Dr. Simon G. Kukes, Executive Chairman of the Company's Board of Directors (Director since July 2018 and Executive Chairman since January 2025)
Dr. Simon G. Kukes is a global investor and executive with over 40 years’ experience in the oil industry. He recently served as the Chief Executive Officer of the Company from July 2018 until January 2025, when he stepped down and assumed the position of Executive Chairman of the Board of the Company. He also previously served as the principal of his personal investment company, SK Energy LLC, from April 2013 until its dissolution in December 2022. From January 2005 to April 2013, Dr. Kukes was an investor and CEO of Samara-Nafta, a joint venture with the U.S.-based international oil company Hess Corporation, and from 2003 to 2004 he served as CEO and Chairman of Yukos Oil Company. From 1998 until it combined with British Petroleum in 2003 to create TNK-BP, Dr. Kukes served as Chief Executive of Tyumen Oil Company (TNK). From 1979 to 1986 he served as Technical Director and Vice President of Business Development for Phillips Petroleum and Amoco. Dr. Kukes (who is a dual citizen of the United States and Israel) currently serves on the board of directors and is an investor in numerous international companies, including Leverate Technological Trading Ltd., an Israel-based technology company and trading platform provider (since October 2014 and as Chairman for two years), Fletschhorn, a Swiss-based hotel and restaurant company (as Chairman since June 2014), and GLAMZ Ltd., a privately-held Israel-based booking platform for the beauty industry (as Chairman since June 2018). In addition, from 1999 to 2007 Dr. Kukes served on the board of directors of global pharmaceutical company Amarin Corporation (Nasdaq: AMRN), and from 2000 to 2003 on the board of directors of Tulsa, Oklahoma-based Parker Wellbore (formerly NYSE-listed Parker Drilling Company), a global provider of contract drilling and drilling-related services.
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Dr. Kukes holds a Bachelor of Science in Chemical Engineering, a PhD in Physical Chemistry, and he attended Rice University in Houston, Texas, where he was a Postdoctoral Fellow. Dr. Kukes has also served as an Adjunct Professor at the University of Delaware and on the Editorial Board of Fuel Magazine, and is also the holder of more than 130 U.S. patents. Dr. Kukes has been recognized for many of achievements over his lifetime, including being voted by the Wall Street Journal as one of the Top 10 Central European Executives in 1999, and named by The Financial Times and PricewaterhouseCoopers as one of the 64 most respected business leaders in the world in 2003.
J. Douglas Schick, President, Chief Executive Officer and Director (President since August 2018 and Chief Executive Officer and Director since January 2025)
Mr. Schick has over twenty-five years of experience in the oil and gas industry. Prior to joining the Company as President on August 1, 2018, followed by his appointment as Chief Executive Officer and Director of the Company in January 2025, Mr. Schick was employed by American Resources, Inc., a Houston, Texas-based privately-held oil and gas investment, development and operating company which he co-founded and continues to serve as Chief Executive Officer (from August 2017 to the present) and formerly as Chief Financial Officer and Vice President of Business Development (from August 2013 to August 2017), provided that Mr. Schick’s service to American Resources requires only minimal time commitment from Mr. Schick that does not conflict with his duties and responsibilities to the Company. Prior to starting American Resources, Mr. Schick served as the founder, owner and principal of J. Douglas Enterprises, a Houston, Texas-based energy industry focused business development and financial consulting firm (from June 2011 to August 2013) as Vice President of Finance (from January 2011 until its sale in June 2011) for Highland Oil and Gas, a private equity-backed E&P company headquartered in Houston, Texas, as Manager of Planning and then Director of Planning at Houston, Texas-based Mariner Energy, Inc. (from December 2006 until its merger with Apache Corp. in December 2010), and in various roles of increasing responsibility in finance, planning, M&A, treasury and accounting at The Houston Exploration Company, ConocoPhillips and Shell Oil Company (from 1998 to 2006).
Mr. Schick holds a BBA in Finance from New Mexico State University and an MBA with a specialization in Finance from Tulane University.
Paul A. Pinkston, Chief Accounting Officer (since December 2018)
Mr. Pinkston brings over 20 years of accounting, compliance, and financial reporting expertise to the Company, with extensive experience in handling and managing corporate compliance, financial reporting and audits, and other regulatory functions for companies engaged in the oil and gas industry in the U.S. Prior to joining the Company on December 1, 2018, from August 2017 to February 2018, Mr. Pinkston served as Corporate Controller and Secretary for Trecora Resources (NYSE: TREC), a Sugar Land, Texas-based petrochemical manufacturing and customer processing service company. Prior to joining Trecora Resources, from May 2013 to June 2017, Mr. Pinkston served in various roles of increasing authority and responsibility at Camber Energy, Inc. (NYSE American: CEI), a Houston, Texas-based oil and gas exploration and production company, including as Camber Energy’s Chief Accounting Officer, Secretary and Treasurer (August 2016 to June 2017), and as its Director of Financial Reporting (May 2013 to August 2016). Before joining Camber Energy, Mr. Pinkston served as a Senior Consultant with Sirius Solutions LLLP, where he performed accounting, audit and finance consulting services (January 2006 to May 2013), as a Corporate Auditor performing internal audits for Baker Hughes, Inc. (January 2002 to November 2005), and as a Senior Auditor, conducting public and private audits, at Arthur Andersen LLP (from September 1998 to November 2001).
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Mr. Pinkston received a Bachelor of Business Administration (Finance and Marketing) degree from the University of Texas and earned a Master of Business Administration (Accounting) degree from the University of Houston. Mr. Pinkston is a Certified Public Accountant registered in the State of Texas.
Clark R. Moore, Executive Vice President, General Counsel and Secretary (since July 2012)
Mr. Moore has served as the Executive Vice President, General Counsel, and Secretary of Pacific Energy Development since its inception in February 2011, and has served as the Executive Vice President, General Counsel, and Secretary of the Company since its acquisition of Pacific Energy Development in July 2012. Mr. Moore began his career in 2000 as a corporate attorney at the law firm of Venture Law Group located in Menlo Park, California, which later merged into Heller Ehrman LLP in 2003. In 2004, Mr. Moore left Heller Ehrman LLP and launched a legal consulting practice focused on representation of private and public company clients in the energy and high-tech industries. In September 2006, Mr. Moore joined Erin Energy Corporation (OTCMKTS:ERN) (formerly CAMAC Energy, Inc.), an independent energy company headquartered in Houston, Texas, as its acting General Counsel and continued to serve in that role through February 2011, when he left to serve as a co-founder of Pacific Energy Development. In addition, since June 1, 2018, Mr. Moore has served as a partner at Foundation Law Group, LLP.
Mr. Moore received his J.D. with Distinction from Stanford Law School and his B.A. with Honors from the University of Washington.
Jody D. Crook, Chief Commercial Officer (since January 2025)
Mr. Crook has over twenty-five years of experience in the oil and gas industry. Prior to his appointment as Chief Commercial Officer of the Company effective January 1, 2025, Mr. Crook served as a Senior Advisor for Land and Business Development activities for the Company, both as an employee and consultant, since April 2020. Before his tenure at the Company, in 2015 Mr. Crook co-founded Tenet Advisory Group LLC, a Houston-based consulting firm that provides engineering, land, regulatory, and business development services to clients in the oil and gas sector, for which Mr. Crook continues to serve as a principal and provide limited consulting services to, provided that Mr. Crook’s service to Tenant Advisory Group and its clients requires only a minimal time commitment from Mr. Crook and does not conflict with his duties and responsibilities to the Company. Additionally, from 2017 to 2018, Mr. Crook co-founded and served as principal of Bronze Four Resources, LLC, an Austin, Texas-based contract operating company focused on contract drilling, completion, and production operations in the Anadarko basins. Prior to establishing Tenet Advisory Group and Bronze Four Resources, Mr. Crook held various leadership roles at Jones Energy, Ltd., a public oil and gas company in Austin, Texas, from June 2004 to December 2014. His positions included Land Manager, Senior Vice President of Land, Senior Vice President for the Arkoma Region, and Senior Vice President of Acquisitions & Exploration. Mr. Crook began his career in Enron Corp’s Analyst and Associates Program, where he completed rotations in Risk Management and Global LNG from January 2000 to November 2001.
Mr. Crook holds a BBA in Finance & PLM from the University of Oklahoma and an MBA from the University of Texas at Austin.
John J. Scelfo, Director (Director since July 2018)
Mr. Scelfo brings over 40 years of experience in oil and gas management, finance and accounting to the PEDEVCO Board. Mr. Scelfo currently serves as principal and owner of JJS Capital Group, a Fort Lauderdale, Florida-based family investment company that he formed in April 2014. Prior to forming JJS Capital, Mr. Scelfo was Senior Vice President, Finance and Corporate Development (from February 2004 to March 2014), and Chief Financial Officer, Worldwide Exploration & Producing (from April 2003 to January 2004) of New York, New York-based Hess Corporation, a large integrated oil and gas company, where he served as one of eight members of the company’s Executive Committee and was responsible for the company’s corporate treasury, strategy and upstream commercial activities. Prior to joining Hess Corporation, Mr. Scelfo served as Executive Vice President and Chief Financial Officer of publicly listed Sirius Satellite Radio (from April 2001 to March 2003), as Vice President and Chief Financial Officer of Asia Pacific & Japan for Dell Computer (November 1999 to March 2001), and in various roles of increasing responsibility with Mobil Corporation (from June 1980 to October 1999).
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Mr. Scelfo holds a bachelor’s degree and an M.B.A. from Cornell University. In 2011, he was awarded Cornell ILR School’s Alpern Award given to those who “have been exceedingly generous in their support of the ILR School in general and in support of Off-Campus Credit Programs in particular.”
H. Douglas Evans, Director (Director since September 2018)
Mr. Evans has 50 years of oil and gas industry experience, 40 years of which have been spent in various executive management positions with Gulf Interstate Engineering Company (“GIE”), a privately-held Houston, Texas-based firm specializing in the engineering of oil, gas and liquid pipeline systems, where he has served as Honorary Chairman since November 2017, and previously served as President and Chief Executive Officer (July 2004-November 2017), President (February 2003-November 2017), Senior Vice President (September 1994-July 2004), and in various other roles since he joined the company in 1978. During Mr. Evans’ tenure as an executive at GIE, he has successfully overseen the company’s organic growth from $25 million in sales in 1996 to over $250 million in sales in recent years, with GIE involved in almost every major onshore oil and gas pipeline in the world over the last 20 years.
Mr. Evans holds a B.S. Civil Engineering and Master of Business Administration from Queen’s University at Kingston, Ontario, and is a registered Professional Engineer in Ontario and Alberta, Canada. Mr. Evans currently serves as Honorary Chairman of GIE (since November 2017), and previously a member of the Board of Directors of Gulf Interstate Field Services, a GIE affiliate engaged in providing oil and gas pipeline construction inspection services, and a number of other GIE affiliated companies, the Board of Directors and Chairman of the Strategy Committee for the International Pipe Line and Offshore Contractors Association (IPLOCA) (through September 2019), a member of the Board of Houston, Texas-based Crossroads School, Inc. (since 2004), and a former member of the Board of the Cystic Fibrosis Foundation – Texas Gulf Coast Chapter.
Director Qualifications
The Board believes that each of our directors is highly qualified to serve as a member of the Board. Each of the directors has contributed to the mix of skills, core competencies and qualifications of the Board. When evaluating candidates for election to the Board, the Board seeks candidates with certain qualities that it believes are important, including integrity, an objective perspective, good judgment, and leadership skills. Our directors are highly educated and have diverse backgrounds and talents and extensive track records of success in what we believe are highly relevant positions.
Family Relationships
None of our directors are related by blood, marriage, or adoption to any other director, executive officer, or other key employees.
Arrangements between Officers and Directors
There is no arrangement or understanding between our directors and executive officers and any other person pursuant to which any director or officer was or is to be selected as a director or officer. There are also no arrangements, agreements or understandings to our knowledge between non-management shareholders that may directly or indirectly participate in or influence the management of our affairs.
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Other Directorships
No directors of the Company are also directors of issuers with a class of securities registered under Section 12 of the Exchange Act (or which otherwise are required to file periodic reports under the Exchange Act).
Involvement in Certain Legal Proceedings
To the best of our knowledge, during the past ten years, none of our directors or executive officers were involved in any of the following: (1) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (2) any conviction in a criminal proceeding or being a named subject to a pending criminal proceeding (excluding traffic violations and other minor offenses); (3) being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; (4) being found by a court of competent jurisdiction (in a civil action), the SEC or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law; (5) being the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of (i) any Federal or State securities or commodities law or regulation; (ii) any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or (iii) any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or (6) being the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
Board Leadership Structure
Our Board of Directors has the responsibility for selecting our appropriate leadership structure. In making leadership structure determinations, the Board of Directors considers many factors, including the specific needs of our business and what is in the best interests of our shareholders. Our current leadership structure is comprised of a separate Executive Chairman of the Board of Directors, and Chief Executive Officer (“CEO”). Mr. John J. Scelfo formerly served as Chairman of the Company’s Board of Directors until January 1, 2025, upon which date Dr. Simon G. Kukes assumed the Executive Chairman position. Dr. Kukes formerly served as Chief Executive Officer of the Company until January 1, 2025, upon which date Mr. J. Douglas Schick assumed the Chief Executive Officer position and joined the Board of Directors. The Board of Directors does not have a policy as to whether the Executive Chairman should be an independent director, an affiliated director, or a member of management. Our Board of Directors believes that the Company’s current leadership structure is appropriate because it effectively allocates authority, responsibility, and oversight between management (the Company’s President and CEO, Mr. Schick) and the members of our Board of Directors. It does this by giving primary responsibility for the operational leadership and strategic direction of the Company to its CEO, while enabling our Executive Chairman to facilitate our Board of Directors’ oversight of management, promote communication between management and our Board of Directors, and support our Board of Directors’ consideration of key governance matters.
The Board of Directors believes that its programs for overseeing risk, as described below, would be effective under a variety of leadership frameworks and therefore do not materially affect its choice of structure.
The Board evaluates its structure periodically, as well as when warranted by specific circumstances, in order to assess which structure is in the best interests of the Company and its stockholders based on the evolving needs of the Company. This approach provides the Board appropriate flexibility to determine the leadership structure best suited to support the dynamic demands of our business.
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Risk Oversight
Effective risk oversight is an important priority of the Board of Directors. Because risks are considered in virtually every business decision, the Board of Directors discusses risk throughout the year generally or in connection with specific proposed actions. The Board of Directors’ approach to risk oversight includes understanding the critical risks in our business and strategy, evaluating our risk management processes, allocating responsibilities for risk oversight among the full Board of Directors, and fostering an appropriate culture of integrity and compliance with legal responsibilities.
The Board exercises direct oversight of strategic risks to us. Our Audit Committee reviews and assesses our processes to manage business and financial risk and financial reporting risk. It also reviews our policies for risk assessment and assesses steps management has taken to control significant risks. Our Compensation Committee oversees risks relating to compensation programs and policies. In each case management periodically reports to our Board or the relevant committee, which provides the relevant oversight on risk assessment and mitigation. The Nominating and Corporate Governance Committee recommends the slate of director nominees for election to the Company’s Board, identifies and recommends candidates to fill vacancies occurring between annual stockholder meetings, reviews, evaluates and recommends changes to the Company’s corporate governance guidelines, and establishes the process for conducting the review of the Chief Executive Officer’s performance.
Our Executive Chairman can represent the board in communications with stockholders and other stakeholders but cannot individually (however the full Board can) override our Chief Executive Officer on, any risk matters. Additionally, our Executive Chairman has not traditionally provided input on design of the Board itself, which instead comes from the full Board.
While the Board and its committees oversee the Company’s strategy, management is charged with its day-to-day execution. To monitor performance against the Company’s strategy, the Board receives regular updates and actively engages in dialogue with management.
Director Independence
Our Board of Directors has determined that Mr. Scelfo and Mr. Evans are independent directors as defined in the NYSE American rules governing members of boards of directors and as defined under Rule 10A-3 of the Exchange Act. Accordingly, over 50% of the members of our Board of Directors are independent as defined in the NYSE American rules governing members of boards of directors and as defined under Rule 10A-3 of the Exchange Act.
In assessing director independence, the Board considers, among other matters, the nature and extent of any business relationships, including transactions conducted, between the Company and each director and between the Company and any organization for which one of our directors is a director or executive officer or with which one of our directors is otherwise affiliated.
Furthermore, the Board has determined that each of the members of our Audit Committee, Compensation Committee, and Nominating and Corporate Governance Committee, is independent within the meaning of NYSE American director independence standards applicable to members of such committees, as currently in effect.
Committees of our Board of Directors
On September 5, 2013, and effective September 10, 2013, the Board of Directors adopted charters for the Nominating and Corporate Governance Committee, Compensation Committee and Audit Committee. We currently maintain a Nominating and Corporate Governance Committee, Compensation Committee and Audit Committee.
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The committees of the Board of Directors consist of the following members as of the date of this filing:
Director | Audit Committee | Compensation Committee | Nominating and Corporate Governance Committee | Independent | ||||
Dr. Simon G. Kukes (1) | ||||||||
J. Douglas Schick |
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|
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John J. Scelfo | C | C | M | X | ||||
H. Douglas Evans | M | M | C | X |
C - Chairman of Committee.
M – Member.
(1) – Executive Chairman of the Board of Directors.
Each of these committees has the duties described below and operates under a charter that has been approved by our Board of Directors. The Charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee are each incorporated by reference as Exhibits 99.4, 99.3 and 99.2, respectively, to this Annual Report and are posted on our website. Our website address is http://www.PEDEVCO.com. Information contained on our website is expressly not incorporated by reference into this Annual Report.
Audit Committee
The audit committee selects, on behalf of our Board of Directors, an independent public accounting firm to audit our financial statements, discusses with the independent auditors their independence, reviews and discusses the audited financial statements with the independent auditors and management, and recommends to the Board of Directors whether the audited financial statements should be included in our annual reports to be filed with the SEC. Mr. Scelfo serves as Chair of the Audit Committee and our Board of Directors has determined that Mr. Scelfo is an “audit committee financial expert” as defined under Item 407(d)(5) of Regulation S-K of the Exchange Act.
The Audit Committee also has various other responsibilities including: pre-approval of all audit and permitted non-audit and tax services that may be provided by the Company’s independent registered public accounting firm or by other accounting firms engaged by the Company; reviewing the Company’s annual audited financial statements and quarterly financial statements, including the notes to such financial statements, the draft annual audit report and the accompanying “management’s discussion and analysis of financial condition and results of operations” with management and the independent registered public accounting firm prior to filing such financial statements with the SEC; reviewing the Company’s earnings press releases with management and the Company’s independent registered public accounting firm prior to the public dissemination of such press releases; meeting separately, and periodically, with the Company’s Chief Executive Officer and Chief Accounting Officer, members of the Company’s internal audit department and the Company’s independent registered public accounting firm to discuss the matters that are the subject of the Charter of the Audit Committee and, if appropriate, inviting some or all of such persons to applicable portions of Committee meetings; reviewing with management and the Company’s independent registered public accounting firm the effectiveness of the Company’s internal control over financial reporting; reviewing and approving the functions of the Company’s internal audit department, including its purpose, organization, responsibilities and performance; reviewing with the Company’s counsel legal matters that may have a material impact on the Company’s financial statements; reviewing and approving candidates for the positions of Chief Accounting Officer and Controller of the Company; and reviewing and, if appropriate, approving proposed transactions between the Company and “related persons” as defined in Item 404 of SEC Regulation S-K, and developing policies and procedures for the review and approval of such transactions.
During the year ended December 31, 2024, the audit committee held four meetings.
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Compensation Committee
The Compensation Committee has various responsibilities including: reviewing annually and approving the corporate objectives relevant to the compensation of all officers of the Company; reviewing annually and determining, or recommending to the Board for determination, the salary, bonus and other non-equity based elements of total compensation for each officer; reviewing annually, determining and awarding to officers any stock option grants and other discretionary awards under the Company’s stock option or other equity incentive plans that the Committee believes are appropriate; approving (or recommending to the Board for determination) all special perquisites, special cash payments and other special compensation and benefit arrangements for officers; considering the results of the most recent “say-on-pay” vote by the Company’s shareholders in connection with the Company’s annual meeting of shareholders; preparing an annual report on executive compensation for inclusion in the Company’s annual proxy statement, if required by the rules and regulations of the SEC; reviewing, and recommending to the Board for determination, the compensation for non-employee directors; granting stock options and other discretionary awards under the Company’s stock option or other equity incentive plans to eligible individuals in the Company’s service who are not officers; and approving (or recommending to the Board for determination) any employment or severance agreements for officers. Mr. Scelfo serves as Chair of the compensation committee.
During the year ended December 31, 2024, the compensation committee held three meetings.
Compensation Committee Interlocks and Insider Participation
The current members of the compensation committee are Messrs. John J. Scelfo (Chairman) and H. Douglas Evans, who are each independent members of our Board of Directors. No member of the compensation committee is an employee or a former employee of the Company. During fiscal 2024, none of our executive officers served on the compensation committee (or its equivalent) or Board of Directors of another entity whose executive officer served on our Compensation Committee. Accordingly, the compensation committee members have no interlocking relationships required to be disclosed under SEC rules and regulations.
Nominating and Corporate Governance Committee
The nominating and corporate governance committee assists our Board of Directors in fulfilling its responsibilities by: identifying and approving individuals qualified to serve as members of our Board of Directors, selecting director nominees for our annual meetings of shareholders, evaluating the performance of our Board of Directors, and developing and recommending to our Board of Directors corporate governance guidelines and oversight procedures with respect to corporate governance and ethical conduct. Mr. Scelfo serves as Chair of the nominating and corporate governance committee.
The nominating and governance committee of the Board of Directors considers nominees for director based upon a number of qualifications, including their personal and professional integrity, ability, judgment, and effectiveness in serving the long-term interests of our shareholders. There are no specific, minimum or absolute criteria for membership on the Board of Directors. The committee makes every effort to ensure that the Board of Directors and its committees include at least the required number of independent directors, as that term is defined by applicable standards promulgated by the NYSE American and/or the SEC.
The nominating and governance committee may use its network of contacts to compile a list of potential candidates. The nominating and governance committee has not in the past relied upon professional search firms to identify director nominees but may engage such firms if so desired. The nominating and governance committee may meet to discuss and consider candidates’ qualifications and then choose a candidate by majority vote.
The nominating and governance committee will consider qualified director candidates recommended in good faith by shareholders, provided those nominees meet the requirements of NYSE American and applicable federal securities law. The nominating and governance committee’s evaluation of candidates recommended by shareholders does not differ materially from its evaluation of candidates recommended from other sources. The Committee will consider candidates recommended by shareholders if the information relating to such candidates are properly submitted in writing to the Secretary of the Company in accordance with the manner described for shareholder proposals under “Stockholder Proposals for 2025 Annual Meeting of Stockholders and 2025 Proxy Materials” beginning on page 53 of our definitive proxy statement for the 2024 Annual Meeting of stockholders. Individuals recommended by stockholders in accordance with these procedures will receive the same consideration received by individuals identified to the Committee through other means.
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During the year ended December 31, 2024, the nominating and corporate governance committee held two meetings.
Website Availability of Documents
The charters of the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee and our Code of Business Conducts and Ethics can be found on our website at https://pedevco.com/ped/corporate_governance. Unless specifically stated herein, documents and information on our website are not incorporated by reference in this Report.
Outside Advisors
Our Board and each of its committees may retain outside advisors, legal counsel, and consultants of their choosing at our expense. The Board and its committees need not obtain management’s consent to retain such outside advisors, legal counsel, and consultants.
Controlled Company Status
Because Dr. Kukes controls a majority of our outstanding voting power, we are a “controlled company” under the corporate governance rules of the NYSE American. Therefore, we are not required to have a majority of our Board of Directors be independent, nor are we required to have a compensation committee or an independent nominating function. We have nevertheless opted to meet the requirements under the NYSE American listing rules for smaller reporting companies, such as the Company, which requires a Board of Directors be comprised of at least 50% independent directors and to have a compensation, nominating and governance committee comprised of independent directors, as more fully described herein.
Pledging of Shares
The ability of our directors and executive officers to pledge Company stock for personal loans and investments is inherently related to their compensation due to our use of equity awards and promotion of long-termism and an ownership culture. As such, the Company has no policies in place preventing or limiting any officer or directors’ ability to pledge their stock, other than limitations imposed pursuant to our Code of Business Conducts and Ethics and our Insider Trading Policy.
Insider Trading/Anti-Hedging Policies
The Company has an insider trading policy governing the purchase, sale and other dispositions of the Company’s securities that applies to all Company personnel, including directors, officers, employees, and other covered persons. The Company also plans to follow procedures for the repurchase of any shares of its securities. The Company believes that its insider trading policy and planned repurchase procedures are reasonably designed to promote compliance with insider trading laws, rules and regulations, and listing standards applicable to the Company. A copy of the Company’s insider trading policy is filed as Exhibit 19.1 to this Annual Report.
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The policy also prohibits the unauthorized disclosure of any nonpublic information acquired in the workplace and the misuse of material nonpublic information in securities trading and includes specific anti-hedging provisions.
To ensure compliance with the policy and applicable federal and state securities laws, all individuals subject to the policy must refrain from the purchase or sale of our securities except in designated trading windows or pursuant to preapproved 10b5-1 trading plans. Even during a trading window period, certain identified insiders, which include the named executive officers and directors, must comply with our designated pre-clearance policy prior to trading in our securities. The anti-hedging provisions prohibit all employees, officers and directors from engaging in “short sales” of our securities or from trading in options
Policy on Timing of Award Grants
The Compensation Committee and the Board have not established policies and practices (whether written or otherwise) regarding the timing of option grants, stock appreciation rights and similar awards, or other awards, in relation to the release of material nonpublic information (“MNPI”) and do not take MNPI into account when determining the timing and terms of stock option or other equity awards to executive officers. The Company does not time the disclosure of MNPI, whether positive or negative, for the purpose of affecting the value of executive compensation.
Rule 10b5-1 Trading Plans
Our executive officers and directors are encouraged to conduct purchase or sale transactions under a trading plan established pursuant to Rule 10b5-1 under the Exchange Act. Through a Rule 10b5-1 trading plan, the executive officer or director contracts with a broker to buy or sell shares of our common stock on a periodic basis. The broker then executes trades pursuant to parameters established by the executive officer or director when entering into the plan, without further direction from them. The executive officer or director may amend or terminate the plan in specified circumstances.
Policy on Equity Ownership
The Company does not have a policy on equity ownership at this time. However, as illustrated in the beneficial ownership table under “ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.”, below, all Named Executive Officers and directors are beneficial owners of stock of the Company.
Compensation Recovery and Clawback Policies
Under the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), in the event of misconduct that results in a financial restatement that would have reduced a previously paid incentive amount, we can recoup those improper payments from our Chief Executive Officer and Chief Financial Officer (if any). The SEC also recently adopted rules which direct national stock exchanges to require listed companies to implement policies intended to recoup bonuses paid to executives if the company is found to have misstated its financial results. Additionally, on November 8, 2023, the Board of Directors of the Company adopted a Policy for the Recovery of Erroneously Awarded Incentive-Based Compensation (the “Clawback Policy”), to comply with the final clawback rules adopted by the U.S. Securities and Exchange Commission under Section 10D and Rule 10D-1 of the Securities Exchange Act of 1934, as amended (“Rule 10D-1”), and the listing standards, as set forth in the New York Stock Exchange Listed Company Manual (the “NYSE Rules” and, together with Rule 10D-1, the “Final Clawback Rules”). The Clawback Policy provides for the mandatory recovery of erroneously awarded incentive compensation from current and former officers of the Company as defined in Rule 10D-1 (“Covered Officers”) in the event the Company is required to prepare an accounting restatement as specified in the Clawback Policy. Under the Clawback Policy, the Board may recoup from the Covered Officers erroneously awarded incentive compensation received within a lookback period of the three completed fiscal years preceding the date on which the Company is required to prepare an accounting restatement. The Clawback Policy is effective as of October 2, 2023.
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The Company determined that the restatement described in the explanatory note at the beginning of this Annual Report on Form 10-K would not result in the recoupment of any compensation because none of the Company’s prior incentive compensation was based on the achievement of any specific net income or other milestones which were affected by the restatement, and because the restatement resulted in an overall increase in net income in the affected periods. Accordingly, the restatement did not impact the Company’s executive compensation payments and the Company determined that there were no payments required to be pursued under the Company’s Policy for the Recovery of Erroneously Awarded Incentive-Based Compensation.
Meetings of the Board of Directors and Annual Meeting
During the fiscal year that ended on December 31, 2024, the Board held ten meetings and took various other actions via the unanimous written consent of the Board of Directors and the various committees described above. All directors attended all of the Board of Directors’ meetings and committee meetings relating to the committees on which each director served during fiscal year 2024. The Company held annual shareholders meetings on June 26, 2014, October 7, 2015, December 28, 2016, December 28, 2017, September 27, 2018, August 28, 2019, August 27, 2020, September 1, 2021, August 25, 2022, August 31, 2023, and August 29, 2024, at which meetings all directors were present in person, via teleconference or via virtual attendance. Each director of the Company is expected to be present at annual meetings of shareholders, absent exigent circumstances that prevent their attendance. Where a director is unable to attend an annual meeting in person but is able to do so by electronic conferencing, the Company will arrange for the director’s participation by means where the director can hear, and be heard, by those present at the meeting.
Executive Sessions of the Board of Directors
The independent members of our Board of Directors meet in executive session (with no management directors or management present) from time to time. The executive sessions include whatever topics the independent directors deem appropriate.
Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (“Dodd-Frank”)
Dodd-Frank requires public companies to provide shareholders with an advisory vote on compensation of the most highly compensated executives, which are sometimes referred to as “say on pay,” as well as an advisory vote on how often the company will present say on pay votes to its shareholders. The Company’s shareholders voted on say-on-pay matters in 2023 and approved a three year-frequency for future “say on pay” votes, with the next such vote being held at the Company’s 2026 annual meeting.
Code of Ethics
In 2012, in accordance with SEC rules, our Board of Directors adopted a Code of Business Conduct and Ethics for our directors, officers and employees. Our Board of Directors believes that these individuals must set an exemplary standard of conduct. This code sets forth ethical standards to which these persons must adhere and other aspects of accounting, auditing and financial compliance, as applicable. The Code of Business Conduct and Ethics is available on our website at www.PEDEVCO.com. Please note that the information contained on our website is not incorporated by reference in, or considered to be a part of, this Annual Report.
We intend to disclose any amendments to our Code of Business Conduct and Ethics and any waivers with respect to our Code of Business Conduct and Ethics granted to our principal executive officer, our principal financial officer, or any of our other employees performing similar functions on our website at www.PEDEVCO.com, within four business days after the amendment or waiver. In such case, the disclosure regarding the amendment or waiver will remain available on our website for at least 12 months after the initial disclosure. There have been no waivers granted with respect to our Code of Business Conduct and Ethics to any such officers or employees to date.
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Shareholder Communications
Our stockholders and other interested parties may communicate with members of the Board of Directors by submitting such communications in writing to our Corporate Secretary, 575 N. Dairy Ashford, Suite 210, Houston, Texas 77079 who, upon receipt of any communication other than one that is clearly marked “Confidential,” will note the date the communication was received, open the communication, make a copy of it for our files and promptly forward the communication to the director(s) to whom it is addressed. Upon receipt of any communication that is clearly marked “Confidential,” our Corporate Secretary will not open the communication, but will note the date the communication was received and promptly forward the communication to the director(s) to whom it is addressed. If the correspondence is not addressed to any particular board member or members, the communication will be forwarded to a board member to bring to the attention of the Board of Directors.
Delinquent Section 16(a) Reports
Section 16(a) of the Exchange Act requires our executive officers and directors and persons who own more than 10% of a registered class of our equity securities to file with the SEC initial statements of beneficial ownership, reports of changes in ownership and annual reports concerning their ownership in our common stock and other equity securities, on Form 3, 4 and 5 respectively. Executive officers, directors and greater than 10% stockholders are required by the SEC regulations to furnish our company with copies of all Section 16(a) reports they file.
Based solely on our review of the copies of such reports received by us and on written representation by our officers and directors regarding their compliance with the applicable reporting requirements under Section 16(a) of the Exchange Act, we believe that all filings required to be made under Section 16(a) during 2023 were timely made.
ITEM 11. EXECUTIVE COMPENSATION
Compensation of Executive Officers
The following table sets forth the compensation for services paid in all capacities for the two fiscal years ended December 31, 2024 and 2023 to (a) Dr. Simon G. Kukes, our former Chief Executive Officer and Director, (b) J. Douglas Schick, our President and Chief Executive Officer, (c) Clark R. Moore, our Executive Vice President, General Counsel and Secretary, and (d) Paul A Pinkston, our Chief Accounting Officer (collectively, the “Named Executive Officers”). There were no other executive officers who received compensation in excess of $100,000 in either 2024 or 2023.
Name and Principal Position |
| Fiscal Year |
| Salary ($) |
|
| Bonus ($)** |
|
| Stock Awards ($) |
|
| Option Awards ($) |
|
| All Other Compensation ($) |
|
| Total ($) |
| ||||||
Dr, Simon G. Kukes |
| 2024 |
|
| - |
|
|
| - |
|
|
| 367,125 | (1) |
|
| - |
|
|
| - |
|
|
| 367,125 |
|
Executive Chairman and Former Chief Executive Officer* |
| 2023 |
|
| - |
|
|
| - |
|
|
| 436,000 | (2) |
|
| - |
|
|
| - |
|
|
| 436,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| - |
|
|
|
|
|
|
|
|
|
J. Douglas Schick |
| 2024 |
|
| 303,297 |
|
|
| 120,000 |
|
|
| 350,438 | (3) |
|
| - |
|
|
| 13,979 | (4) |
|
| 788,714 |
|
President and Chief Executive Officer# |
| 2023 |
|
| 290,000 |
|
|
| 102,000 |
|
|
| 381,500 | (5) |
|
| - |
|
|
| 13,587 | (4) |
|
| 787,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| - |
|
|
|
|
|
|
|
|
|
Clark R. Moore |
| 2024 |
|
| 292,833 |
|
|
| 110,000 |
|
|
| 300,375 | (6) |
|
| - |
|
|
| 18,307 | (4) |
|
| 721,515 |
|
Executive Vice President, General Counsel and Secretary |
| 2023 |
|
| 280,000 |
|
|
| 98,000 |
|
|
| 327,000 | (7) |
|
| - |
|
|
| 19,800 | (4) |
|
| 724,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| - |
|
|
|
|
|
|
|
|
|
Paul A. Pinkston |
| 2024 |
|
| 167,333 |
|
|
| 35,000 |
|
|
| 166,875 | (8) |
|
| - |
|
|
| 12,140 | (4) |
|
| 381,348 |
|
Chief Accounting Officer |
| 2023 |
|
| 160,000 |
|
|
| 37,000 |
|
|
| 218,000 | (9) |
|
| - |
|
|
| 11,820 | (4) |
|
| 428,333 |
|
*Chief Executive Officer in 2023 and 2024; departed from Chief Executive Officer position and assumed Executive Chairman position effective January 1, 2025.
**Annual bonus awards are paid in January each year and are for performance bonuses accrued over the prior calendar year.
#President in 2023 and 2024; appointed President and Chief Executive Officer effective January 1, 2025.
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Summary Compensation Table
Does not include perquisites and other personal benefits or property, unless the aggregate amount of such compensation is more than $10,000. No executive officer earned any non-equity incentive plan compensation or nonqualified deferred compensation during the periods reported above. Bonus payments to executive officers were awarded at the discretion of the Board of Directors based on an assessment of the Company’s and each individual executive officer’s performance without reference to any specific individual performance objectives. Stock Awards represent the aggregate grant date fair value of awards computed in accordance with Financial Accounting Standards Board Accounting Standard Codification Topic 718. For additional information on the valuation assumptions with respect to the restricted stock grants, refer to “Part II” - “Item 8. Financial Statements and Supplementary Data” - “Note 12 – Share-Based Compensation”. These amounts do not correspond to the actual value that will be recognized by the named individuals from these awards. No executive officer serving as a director received any compensation for services on the Board of Directors separate from the compensation paid as an executive for the periods above.
(1) | Consists of the value of 550,000 shares of restricted common stock granted in January 2024 at $0.6675 per share. |
(2) | Consists of the value of 400,000 shares of restricted common stock granted in January 2023 at $1.09 per share. |
(3) | Consists of the value of 525,000 shares of restricted common stock granted in January 2024 at $0.6675 per share. |
(4) | Consists of Company matching contributions of up to 6% of the applicable officer's salary into the Company's sponsored 401(k) plan, subject to IRS and plan limits. |
(5) | Consists of the value of 350,000 shares of restricted common stock granted in January 2023 at $1.09 per share. |
(6) | Consists of the value of 450,000 shares of restricted common stock granted in January 2024 at $0.6675 per share. |
(7) | Consists of the value of 300,000 shares of restricted common stock granted in January 2023 at $1.09 per share. |
(8) | Consists of the value of 250,000 shares of restricted common stock granted in January 2024 at $0.6675 per share. |
(9) | Consists of the value of 200,000 shares of restricted common stock granted in January 2023 at $1.09 per share. |
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Outstanding Equity Awards at Year Ended December 31, 2024
The following table sets forth information as of December 31, 2024 concerning outstanding equity awards for the executive officers named in the Summary Compensation Table.
Outstanding Equity Awards at Fiscal Year-End
|
| Option Awards |
|
| Stock Awards(4) |
| ||||||||||||||||||
Name |
| Number of securities underlying unexercised options (#) exercisable |
|
| Number of securities underlying unexercised options (#) unexercisable |
|
| Option Exercise price ($) |
|
| Option expiration date |
|
| Number of shares or units of stock that have not vested (#) |
|
| Market value of shares or units of stock that have not vested ($)(5) |
| ||||||
Dr. Simon G. Kukes |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 133,334 | (1) |
| $ | 103,734 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 266,667 | (2) |
| $ | 207,467 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 550,000 | (3) |
| $ | 427,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J. Douglas Schick |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 100,000 | (1) |
| $ | 77,800 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 233,334 | (2) |
| $ | 181,534 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 525,000 | (3) |
| $ | 408,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Clark R. Moore |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 100,000 | (1) |
| $ | 77,800 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 200,000 | (2) |
| $ | 155,600 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 450,000 | (3) |
| $ | 350,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul A. Pinkston |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 66,667 | (1) |
| $ | 51,867 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 133,334 | (2) |
| $ | 103,734 |
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 250,000 | (3) |
| $ | 194,500 |
|
(1) | Stock award vested on January 25, 2025, and was subject to the holder remaining an employee of or consultant to the Company on such vesting dates. |
(2) | Stock award vests 50% on January 23, 2025 (vested), and January 23, 2026, subject to the holder remaining an employee of or consultant to the Company on such vesting dates. |
(3)
| Stock award vests 33.3% on January 26, 2025 (vested), 33.3% on January 26, 2026, and 33.4% on January 26, 2027, subject to the holder remaining an employee of or consultant to the Company on such vesting dates. |
(4) (5)
| There were no unearned shares, units or other rights that have not vested as of December 31, 2024. Calculated by multiplying the closing market price of the Company’s common stock at the end of the last completed fiscal year (December 31, 2024 and $0.778 per share) by the number of shares of stock. |
Issuances of Equity to Executive Officers
See above and see also “Part II” - “Item 8. Financial Statements and Supplementary Data” – “Note 12 – Share-Based Compensation”, for equity issuances to executive officers for the years ended December 31, 2024 and 2023, respectively.
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Compensation of Directors
We compensate our Board members with stock-based compensation from time to time, as consideration for their services to the Board. Our executive officers are not paid any consideration for their service to the Board separate from the consideration they are paid as executive officers of the Company, as shown above.
The following table sets forth compensation information with respect to our non-executive directors during our fiscal year ended December 31, 2024.
Name |
| Fees Earned or Paid in Cash ($)* |
|
| Stock Awards ($) (1) (2) |
|
| All Other Compensation ($) |
|
| Total ($) |
| ||||
John J. Scelfo |
| $ | - |
|
| $ | 109,500 |
|
| $ | - |
|
| $ | 109,500 |
|
H. Douglas Evans |
| $ | - |
|
| $ | 74,460 |
|
| $ | - |
|
| $ | 74,460 |
|
* The table above does not include the amount of any expense reimbursements paid to the above directors. No directors received any Non-Equity Incentive Plan Compensation or Nonqualified Deferred Compensation. Does not include perquisites and other personal benefits, or property, unless the aggregate amount of such compensation is more than $10,000.
(1) | Amounts in this column represent the aggregate grant date fair value of awards computed in accordance with Financial Accounting Standards Board Accounting Standard Codification Topic 718. For additional information on the valuation assumptions with respect to the restricted stock grants, refer to “Part II” - “Item 8. Financial Statements and Supplementary Data” - “Note 12 – Share-Based Compensation”. These amounts do not correspond to the actual value that will be recognized by the named individuals from these awards. As of December 31, 2024, the following outstanding and unvested shares of restricted stock were held by each of the above non-executive directors: John J. Scelfo – 125,000 shares; and H. Douglas Evans – 85,000 shares. |
(2) | Mr. Scelfo and Mr. Evans received grants of 125,000 and 85,000 shares of restricted stock, respectively, on August 29, 2024, with an aggregate grant date fair value of $109,500 and $74,460, respectively, which will vest in full on July 12, 2025 and September 27, 2025, respectively, subject to such person’s continued service on the Board. For the year ended December 31, 2024, there was a compensation expense of $64,000 recognized by the Company related to these grants. |
Effective September 27, 2018, the Board no longer has a formal compensation program; provided that the Board of Directors and/or the Compensation Committee may authorize compensation (including, but not limited to cash, options and restricted stock) to the members of the Board of Directors from time to time in their discretion. Additionally, the Board generally grants yearly equity awards in August of each year to the non-executive directors.
Agreements with Current Named Executive Officers
J. Douglas Schick. On August 1, 2018, in connection with his appointment as President of the Company, we entered into an offer letter with J. Douglas Schick, which offer letter was amended effective January 1, 2025 to promote Mr. Schick to the office President and Chief Executive Officer of the Company (as amended, the “Offer Letter”). Pursuant to the Offer Letter, Mr. Schick agreed to serve as an executive officer of the Company on an at-will basis; the Company agreed to pay Mr. Schick $20,833 per month, but has been increased, effective February 1, 2024, to $25,375 per month, and again to $29,166.67 per month effective January 1, 2025; and Mr. Schick is eligible for an annual bonus in the discretion of the Company totaling up to 40% of his then current salary and may also receive bonuses (in any amount) consisting of cash, grants of restricted stock and/or options granted in the Board of Directors’ and/or the Compensation Committee’s sole discretion, from time to time. Additionally, the Board of Directors has historically issued Mr. Schick restricted stock consideration on a yearly basis in consideration for services rendered to the Company, which issuances for 2024 and 2023 are described in the table above. Mr. Schick’s employment may be terminated by him or the Company with 30 days’ prior written notice. In the event Mr. Schick’s employment with the Company is terminated by the Company without “Cause,” the Company will (a) pay Mr. Schick an amount equal to twelve (12) months of his then-current annual base salary, and (b) immediately accelerate by twelve (12) months the vesting of all outstanding Company restricted stock and options exercisable for Company capital stock held by Mr. Schick. For purposes of the Offer Letter, “Cause” means Mr. Schick’s (1) conviction of, or plea of nolo contendere to, a felony or any other crime involving moral turpitude; (2) fraud on or misappropriation of any funds or property of the Company or any of its affiliates, customers or vendors; (3) act of material dishonesty, willful misconduct, willful violation of any law, rule or regulation, or breach of fiduciary duty involving personal profit, in each case made in connection with his responsibilities as an employee, officer or director of the Company and which has, or could reasonably be deemed to result in, a material adverse effect upon the Company; (4) illegal use or distribution of drugs; (5) willful material violation of any policy or code of conduct of the Company; or (6) material breach of any provision of the Offer Letter or any other employment, non-disclosure, non-competition, non-solicitation or other similar agreement executed by him for the benefit of the Company or any of its affiliates, all as reasonably determined in good faith by the Board of Directors of the Company. However, an event that is or would constitute “Cause” shall cease to be “Cause” if he reverses the action or cures the default that constitutes “Cause” within 10 days after the Company notifies him in writing that Cause exists.
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The Offer Letter contains standard confidentiality provisions; a standard non-compete restriction prohibiting Mr. Schick from competing against the Company during the term of his employment and for one year thereafter in connection with any directly competitive enterprise, commercial venture, or project involving petroleum exploration, development, or production activities in the same geographic areas as the Company’s activities or doing business with the Company during the six-month period before the termination of his employment, with certain exceptions; and a non-solicitation provision prohibiting him from inducing or attempting to induce any employee of the company from leaving their employment with the Company and/or attempting to induce any consultant, service provider, customer or business relation of the Company from terminating their relationship with the Company during the term of his employment and for one year thereafter. Mr. Schick’s salary may be increased from time to time in the discretion of the Board or Compensation Committee, without amending the Offer Letter.
Clark R. Moore. Pacific Energy Development, our wholly-owned subsidiary, has entered into an employment agreement, dated June 10, 2011, as amended January 11, 2013 and January 25, 2022, with Clark Moore, its Executive Vice President, Secretary and General Counsel (the “Moore Employment Agreement”), pursuant to which, effective June 1, 2011, Mr. Moore has been employed by Pacific Energy Development, with a current base salary of $24,500 per month, and a target annual cash bonus of between 20% and 40% of his base salary, awardable by the Board of Directors in its discretion, provided that Mr. Moore may also receive bonuses (in any amount) consisting of cash, grants of restricted stock and/or options granted in the Board of Directors’ and/or the Compensation Committee’s sole discretion, from time to time. Additionally, the Board of Directors has historically issued Mr. Moore restricted stock consideration on a yearly basis in consideration for services rendered to the Company, which issuances for 2024 and 2023 are described in the table above. Mr. Moore’s salary may be increased from time to time in the discretion of the Board or Compensation Committee, without amending the Moore Employment Agreement. In addition, Mr. Moore’s employment agreement includes, among other things, severance payment provisions that would require the Company to make lump sum payments equal to 12 months’ salary and target bonus to Mr. Moore, and full acceleration of vesting of any outstanding Company stock options or restricted stock held, in the event his employment is terminated due to his death or disability, terminated without “Cause” or if he voluntarily resigns for “Good Reason” (36 months in connection with a “Change of Control”), and continuation of benefits for up to 36 months (48 months in connection with a “Change of Control”), as such terms are defined in the employment agreement. The employment agreement also prohibits Mr. Moore from engaging in competitive activities during and following termination of his employment that would result in disclosure of our confidential information but does not contain a general restriction on engaging in competitive activities.
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For purposes of the Moore Employment Agreement, the term “Cause” means his (1) conviction of, or plea of nolo contendere to, a felony or any other crime involving moral turpitude; (2) fraud on or misappropriation of any funds or property of our company or any of its affiliates, customers or vendors; (3) act of material dishonesty, willful misconduct, willful violation of any law, rule or regulation, or breach of fiduciary duty involving personal profit, in each case made in connection with his responsibilities as an employee, officer or director of our company and which has, or could reasonably be deemed to result in, a Material Adverse Effect upon our company; (4) illegal use or distribution of drugs; (5) material violation of any policy or code of conduct of our company; or (6) material breach of any provision of the employment agreement or any other employment, non-disclosure, non-competition, non-solicitation or other similar agreement executed by him for the benefit of our company or any of its affiliates, all as reasonably determined in good faith by the Board of Directors of our company. However, an event that is or would constitute “Cause” shall cease to be “Cause” if he reverses the action or cures the default that constitutes “Cause” within 10 days after our company notifies him in writing that Cause exists. No act or failure to act on Mr. Moore’s part will be considered “willful” unless it is done, or omitted to be done, by him in bad faith or without reasonable belief that such action or omission was in the best interests of our company. Any act or failure to act that is based on authority given pursuant to a resolution duly passed by the Board of Directors, or the advice of counsel to our company, shall be conclusively presumed to be done, or omitted to be done, in good faith and in the best interests of the Company.
For purposes of the Moore Employment Agreement, “Material Adverse Effect” means any event, change or effect that is materially adverse to the condition (financial or otherwise), properties, assets, liabilities, business, operations or results of operations of our company or its subsidiaries, taken as a whole.
For purposes of the Moore Employment Agreement, “Good Reason” means the occurrence of any of the following without his written consent: (a) the assignment to him of duties substantially inconsistent with this employment agreement or a material adverse change in his titles or authority; (b) any failure by our company to comply with the compensation provisions of the agreement in any material way; (c) any material breach of the employment agreement by our company; or (d) the relocation of him by more than fifty (50) miles from the location of our company’s office located in Danville, California. However, an event that is or would constitute “Good Reason” shall cease to be “Good Reason” if: (i) he does not terminate employment within 45 days after the event occurs; (ii) before he terminates employment, we reverse the action or cure the default that constitutes “Good Reason” within 10 days after he notifies us in writing that Good Reason exists; or (iii) he was a primary instigator of the “Good Reason” event and the circumstances make it inappropriate for him to receive “Good Reason” termination benefits under the employment agreement (e.g., he agrees temporarily to relinquish his position on the occurrence of a merger transaction he assists in negotiating).
For purposes of the Moore Employment Agreement, “Change of Control” means: (i) a merger, consolidation or sale of capital stock by existing holders of capital stock of our company that results in more than 50% of the combined voting power of the then outstanding capital stock of our company or its successor changing ownership; (ii) the sale, or exclusive license, of all or substantially all of our company’s assets; or (iii) the individuals constituting our company’s Board of Directors as of the date of the employment agreement (the “Incumbent Board of Directors”) cease for any reason to constitute at least 1/2 of the members of the Board of Directors; provided, however, that if the election, or nomination for election by our stockholders, of any new director was approved by a vote of the Incumbent Board of Directors, such new director shall be considered a member of the Incumbent Board of Directors. Notwithstanding the foregoing and for purposes of clarity, a transaction shall not constitute a Change in Control if: (w) its sole purpose is to change the state of our company’s incorporation; (x) its sole purpose is to create a holding company that will be owned in substantially the same proportions by the persons who held our company’s securities immediately before such transaction; or (y) it is a transaction effected primarily for the purpose of financing our company with cash (as determined by the Board of Directors in its discretion and without regard to whether such transaction is effectuated by a merger, equity financing or otherwise).
Mr. Moore’s salary may be increased from time to time in the discretion of the Board or Compensation Committee, without amending the Employment Agreement.
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Paul A. Pinkston.On December 1, 2018, the Company appointed Mr. Pinkston as the Chief Accounting Officer of the Company and Mr. Pinkston commenced employment with the Company pursuant to the terms of an Offer Letter, dated October 16, 2018, and effective December 1, 2018, entered into by and between the Company and Mr. Pinkston (the “Pinkston Offer Letter”). Also effective on December 1, 2018, Mr. Pinkston commenced serving as the Company’s Principal Financial and Accounting Officer.
Pursuant to the Pinkston Offer Letter, Mr. Pinkston agreed to serve as Chief Accounting Officer of the Company on an at-will basis, the Company agreed to pay Mr. Pinkston $11,666.67 per month (which has been increased, effective February 1, 2024, to $14,000 per month), Mr. Pinkston is eligible for an annual bonus in the discretion of the Board of Directors of the Company totaling up to 30% of his then current salary, provided that Mr. Pinkston may also receive bonuses (in any amount) consisting of cash, grants of restricted stock and/or options granted in the Board of Directors’ and/or the Compensation Committee’s sole discretion, from time to time. Additionally, the Board of Directors has historically issued Mr. Pinkston restricted stock consideration on a yearly basis in consideration for services rendered to the Company, which issuances for 2024 and 2023 are described in the table above. Mr. Pinkston’s employment may be terminated by him or the Company with 30 days prior written notice.
The Pinkston Offer Letter contains standard confidentiality provisions and a standard a non-solicitation provision prohibiting him from inducing or attempting to induce any employee of the Company from leaving their employment with the Company and/or attempting to induce any consultant, service provider, customer or business relation of the Company from terminating their relationship with the Company during the term of his employment and for one year thereafter. Mr. Pinkston’s salary may be increased from time to time in the discretion of the Board or Compensation Committee, without amending the Offer Letter.
Jody D Crook.On December 7, 2024, the Company appointed Jody Crook to the office of Chief Commercial Officer of the Company, effective January 1, 2025. The Company and Mr. Crook entered into an Offer Letter, dated December 8, 2024 (the “Crook Offer Letter”), which provides for the appointment of Mr. Crook to the office of Chief Commercial Officer, effective January 1, 2025, at an annual salary of $280,000, with a discretionary annual cash bonus of up to 40% of his then-current salary, a guaranteed cash bonus of $100,000 payable in January 2025, and, subject to Board approval and the Company’s 2021 Plan, the grant of a number of shares of restricted Company Common Stock equal to (x) $250,000 divided by (y) the then-current fair market value of the Company Common Stock as determined under the 2021 Plan, vesting 1/3 per year over three years following the date of grant, subject to Mr. Crook’s continued employment with the Company. Mr. Crook is also eligible to receive additional bonuses from time to time, in cash or equity, in the discretion of the Board. The Crook Offer Letter includes customary confidentiality requirements and conflict of interest provisions. The agreement can be terminated at any time, for any reason, by either party, with thirty days prior written notice.
2024 Bonuses
On January 23, 2025, after recommendation by the Compensation Committee of the Company’s Board of Directors, the Board of Directors of the Company, in connection with the Company’s annual compensation review, approved calendar year 2024 cash bonuses (paid in January 2025) for (i) Mr. Paul Pinkston, the Company’s Chief Accounting Officer, in the amount of $50,000, (ii) Mr. J. Douglas Schick, the President and CEO of the Company, in the amount of $130,000, (iii) Mr. Clark R. Moore, the Executive Vice President, General Counsel and Secretary of the Company, in the amount of $120,000 and (iv) Mr. Jody Crook, the Chief Commercial Officer of the Company, in the amount of $100,000, which was contingent on Mr. Crook’s acceptance of the Crook Offer Letter noted above.
Equity Incentive Plans
2021 Plan
General. On July 10, 2021, our Board of Directors adopted the PEDEVCO Corp. 2021 Equity Incentive Plan, which was approved by our stockholders on September 1, 2021. The 2021 Equity Incentive Plan provides for awards of incentive stock options, non-statutory stock options, rights to acquire restricted stock, stock appreciation rights, or SARs, and performance units and performance shares. On June 27, 2024, the Board of Directors adopted an amended and restated 2021 Equity Incentive Plan, to increase by 5,000,000 shares, the number of awards available for issuance under the plan, which was approved by stockholders on August 29, 2024. Subject to the provisions of the 2021 Equity Incentive Plan relating to adjustments upon changes in our common stock, an aggregate of 13,000,000 shares of common stock were reserved for issuance under the 2021 Equity Incentive Plan.
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We refer to the 2021 Equity Incentive Plan as the 2021 Plan.
Purpose. Our Board of Directors adopted the 2021 Plan to provide a means by which our employees, directors and consultants may be given an opportunity to benefit from increases in the value of our common stock, to assist in attracting and retaining the services of such persons, to bind the interests of eligible recipients more closely to our interests by offering them opportunities to acquire shares of our common stock and to afford such persons stock-based compensation opportunities that are competitive with those afforded by similar businesses.
Administration. Unless it delegates administration to a committee as described below, our Board of Directors will administer the 2021 Plan. Subject to the provisions of the 2021 Plan, our Board of Directors has the power to construe and interpret the 2021 Plan, and to determine: (i) the fair value of common stock subject to awards issued under the 2021 Plan; (ii) the persons to whom and the dates on which awards will be granted; (iii) what types or combinations of types of awards will be granted; (iv) the number of shares of common stock to be subject to each award; (v) the time or times during the term of each award within which all or a portion of such award may be exercised; (vi) the exercise price or purchase price of each award; and (vii) the types of consideration permitted to exercise or purchase each award and other terms of the awards.
Our Board of Directors has the power to delegate administration of the 2021 Plan to a committee composed of one or more directors. In the discretion of our Board of Directors, a committee may consist solely of two or more “independent directors” or two or more “non-employee directors” (as such terms are defined in the 2021 Plan).
Eligibility. Incentive stock options may be granted under the 2021 Plan only to employees of us and our affiliates. Employees, directors and consultants of us and our affiliates are eligible to receive all other types of awards under the 2021 Plan.
Terms of Options and SARs. The exercise price of incentive stock options may not be less than the fair market value of the common stock subject to the option on the date of the grant and, in some cases, may not be less than 110% of such fair market value. The exercise price of non-statutory options also may not be less than the fair market value of the common stock on the date of grant.
Options granted under the 2021 Plan may be exercisable in cumulative increments, or “vest,” as determined by our Board of Directors. Our Board of Directors has the power to accelerate the time as of which an option may vest or be exercised. The maximum term of options, SARs and performance shares and units under the 2021 Plan is ten years, except that in certain cases, the maximum term is five years. Options, SARs and performance shares and units awarded under the 2021 Plan generally will terminate three months after termination of the participant’s service, subject to certain exceptions.
A recipient may not transfer an incentive stock option otherwise than by will or by the laws of descent and distribution. During the lifetime of the recipient, only the recipient may exercise an option, SAR or performance share or unit. Our Board of Directors may grant non-statutory stock options, SARs and performance shares and units that are transferable to the extent provided in the applicable written agreement.
Terms of Restricted Stock Awards. Restricted stock awards may be granted under the 2021 Plan pursuant to restricted stock purchase or grant agreements. No awards of restricted stock may be granted under the 2021 Plan after ten (10) years from our Board of Directors’ adoption of the 2021 Plan (July 2031).
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Shares of restricted stock acquired under a restricted stock purchase or grant agreement may, but need not, be subject to forfeiture to us or other restrictions that will lapse in accordance with a vesting schedule to be determined by our Board of Directors. In the event a recipient’s employment or service with us terminates, any or all of the shares of common stock held by such recipient that have not vested as of the date of termination under the terms of the restricted stock agreement may be forfeited to us in accordance with such restricted stock agreement.
Rights to acquire shares of common stock under the restricted stock purchase or grant agreement shall be transferable by the recipient only upon such terms and conditions as are set forth in the restricted stock agreement, as our Board of Directors shall determine in its discretion, so long as shares of common stock awarded under the restricted stock agreement remain subject to the terms of such agreement.
Adjustment Provisions. If any change is made to our outstanding shares of common stock without our receipt of consideration (whether through reorganization, stock dividend or stock split, or other specified change in our capital structure), appropriate adjustments may be made in the class and maximum number of shares of common stock subject to the 2021 Plan and outstanding awards. In that event, the 2021 Plan will be appropriately adjusted in the class and maximum number of shares of common stock subject to the 2021 Plan, and outstanding awards may be adjusted in the class, number of shares and price per share of common stock subject to such awards.
Effect of Certain Corporate Events. In the event of (i) a liquidation or dissolution of the Company; (ii) a merger or consolidation of the Company with or into another corporation or entity (other than a merger with a wholly-owned subsidiary); (iii) a sale of all or substantially all of the assets of the Company; or (iv) a purchase or other acquisition of more than 50% of the outstanding stock of the Company by one person or by more than one person acting in concert, any surviving or acquiring corporation may assume awards outstanding under the 2021 Plan or may substitute similar awards. Unless the stock award agreement otherwise provides, in the event any surviving or acquiring corporation does not assume such awards or substitute similar awards, then the awards will terminate if not exercised at or prior to such event.
Duration, Amendment and Termination. Our Board of Directors may suspend or terminate the 2021 Plan without stockholder approval or ratification at any time or from time to time. Unless sooner terminated, the 2021 Plan will terminate ten years from the date of its adoption by our Board of Directors, i.e., in July 2031.
Our Board of Directors may also amend the 2021 Plan at any time, and from time to time. However, except as it relates to adjustments upon changes in common stock, no amendment will be effective unless approved by our stockholders to the extent stockholder approval is necessary to preserve incentive stock option treatment for federal income tax purposes. Our Board of Directors may submit any other amendment to the 2021 Plan for stockholder approval if it concludes that stockholder approval is otherwise advisable.
As of the date of this Annual Report, options to purchase 1,774,000 shares of common stock and 6,989,118 shares of restricted stock have been issued and are outstanding under the 2021 Plan, with 4,236,882 shares of common stock remaining available for issuance under the 2021 Plan. The options have a weighted average exercise price of $1.07 per share and have expiration dates ranging from 2027 to 2029.
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2012 Plan
General. On June 26, 2012, our Board of Directors adopted the Blast Energy Services, Inc. 2012 Equity Incentive Plan, which was approved by our stockholders on July 30, 2012 and subsequently renamed to the PEDEVCO Corp. 2012 Equity Incentive Plan in connection with our name change from Blast Energy Services, Inc. to PEDEVCO Corp. The 2012 Equity Incentive Plan provides for awards of incentive stock options, non-statutory stock options, rights to acquire restricted stock, stock appreciation rights, or SARs, and performance units and performance shares. Subject to the provisions of the 2012 Equity Incentive Plan relating to adjustments upon changes in our common stock, an aggregate of 200,000 shares of common stock were reserved for issuance under the 2012 Equity Incentive Plan. On April 23, 2014, the Board of Directors adopted an amended and restated 2012 Equity Incentive Plan, to increase by 500,000 shares, the number of awards available for issuance under the plan, which was approved by stockholders on June 27, 2014. On July 27, 2015, the Board of Directors adopted an amended and restated 2012 Equity Incentive Plan, to increase by 300,000 shares, the number of awards available for issuance under the plan, which was approved by stockholders on October 7, 2015. On October 21, 2016, the Board of Directors adopted an amended and restated 2012 Equity Incentive Plan, to increase by 500,000 shares, the number of awards available for issuance under the plan, which was approved by stockholders on December 28, 2016. On November 6, 2017, the Board of Directors adopted an amended and restated 2012 Equity Incentive Plan, to increase by 1,500,000 shares, the number of awards available for issuance under the plan, which was approved by stockholders on December 28, 2017. On August 10, 2018, the Board of Directors adopted an amended and restated 2012 Equity Incentive Plan, to increase by 3,000,000 shares, the number of awards available for issuance under the plan, which was approved by stockholders on September 27, 2018. On July 1, 2019, the Board of Directors adopted an amended and restated 2012 Equity Incentive Plan, to increase by 2,000,000 shares (to 8,000,000 in aggregate), the number of awards available for issuance under the plan, which was approved by stockholders on August 28, 2019.
We refer to the 2012 Amended and Restated Incentive Plan as the 2012 Plan.
Purpose. Our Board of Directors adopted the 2012 Plan to provide a means by which our employees, directors and consultants may be given an opportunity to benefit from increases in the value of our common stock, to assist in attracting and retaining the services of such persons, to bind the interests of eligible recipients more closely to our interests by offering them opportunities to acquire shares of our common stock and to afford such persons stock-based compensation opportunities that are competitive with those afforded by similar businesses.
Administration. Unless it delegates administration to a committee, our Board of Directors administers the 2012 Plan. Subject to the provisions of the 2012 Plan, our Board of Directors has the power to construe and interpret the 2012 Plan, and to determine: (a) the fair value of common stock subject to awards issued under the 2012 Plan; (b) the persons to whom and the dates on which awards will be granted; (c) what types or combinations of types of awards will be granted; (d) the number of shares of common stock to be subject to each award; (e) the time or times during the term of each award within which all or a portion of such award may be exercised; (f) the exercise price or purchase price of each award; and (g) the types of consideration permitted to exercise or purchase each award and other terms of the awards.
Eligibility. Incentive stock options may be granted under the 2012 Plan only to employees of us and our affiliates. Employees, directors and consultants of us and our affiliates are eligible to receive all other types of awards under the 2012 Plan.
Terms of Options and SARs. The exercise price of incentive stock options may not be less than the fair market value of the common stock subject to the option on the date of the grant and, in some cases, may not be less than 110% of such fair market value. The exercise price of non-statutory options also may not be less than the fair market value of the common stock on the date of grant.
Options granted under the 2012 Plan may be exercisable in cumulative increments, or “vest,” as determined by our Board of Directors. Our Board of Directors has the power to accelerate the time as of which an option may vest or be exercised. The maximum term of options, SARs and performance shares and units under the 2012 Plan is ten years, except that in certain cases, the maximum term is five years. Options, SARs and performance shares and units awarded under the 2012 Plan generally will terminate three months after termination of the participant’s service, subject to certain exceptions.
A recipient may not transfer an incentive stock option otherwise than by will or by the laws of descent and distribution. During the lifetime of the recipient, only the recipient may exercise an option, SAR or performance share or unit. Our Board of Directors may grant non-statutory stock options, SARs and performance shares and units that are transferable to the extent provided in the applicable written agreement.
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Terms of Restricted Stock Awards. Our Board of Directors may issue shares of restricted stock under the 2012 Plan as a grant or for such consideration, including services, and, subject to the Sarbanes-Oxley Act of 2002, promissory notes, as determined in its sole discretion.
Shares of restricted stock acquired under a restricted stock purchase or grant agreement may, but need not, be subject to forfeiture to us or other restrictions that will lapse in accordance with a vesting schedule to be determined by our Board of Directors. In the event a recipient’s employment or service with us terminates, any or all of the shares of common stock held by such recipient that have not vested as of the date of termination under the terms of the restricted stock agreement may be forfeited to us in accordance with such restricted stock agreement.
Rights to acquire shares of common stock under the restricted stock purchase or grant agreement shall be transferable by the recipient only upon such terms and conditions as are set forth in the restricted stock agreement, as our Board of Directors shall determine in its discretion, so long as shares of common stock awarded under the restricted stock agreement remain subject to the terms of such agreement.
Adjustment Provisions. If any change is made to our outstanding shares of common stock without our receipt of consideration (whether through reorganization, stock dividend or stock split, or other specified change in our capital structure), appropriate adjustments may be made in the class and maximum number of shares of common stock subject to the 2012 Plan and outstanding awards. In that event, the 2012 Plan will be appropriately adjusted in the class and maximum number of shares of common stock subject to the 2012 Plan, and outstanding awards may be adjusted in the class, number of shares and price per share of common stock subject to such awards.
Effect of Certain Corporate Events. In the event of (a) a liquidation or dissolution of the Company; (b) a merger or consolidation of the Company with or into another corporation or entity (other than a merger with a wholly-owned subsidiary); (c) a sale of all or substantially all of the assets of the Company; or (d) a purchase or other acquisition of more than 50% of the outstanding stock of the Company by one person or by more than one person acting in concert, any surviving or acquiring corporation may assume awards outstanding under the 2012 Plan or may substitute similar awards. Unless the stock award agreement otherwise provides, in the event any surviving or acquiring corporation does not assume such awards or substitute similar awards, then the awards will terminate if not exercised at or prior to such event.
Duration, Amendment and Termination. Our Board of Directors may suspend or terminate the 2012 Plan without stockholder approval or ratification at any time or from time to time. Unless sooner terminated, the 2012 Plan will terminate ten years from the date of its adoption by our Board of Directors, i.e., in June 2022.
Our Board of Directors may also amend the 2012 Plan at any time, and from time to time. However, except as it relates to adjustments upon changes in common stock, no amendment will be effective unless approved by our stockholders to the extent stockholder approval is necessary to preserve incentive stock option treatment for federal income tax purposes. Our Board of Directors may submit any other amendment to the 2012 Plan for stockholder approval if it concludes that stockholder approval is otherwise advisable.
As of the date of this Annual Report, options to purchase 310,000 shares of common stock remain outstanding and 6,449,503 shares of restricted stock have been issued under the 2012 Plan. The options have a weighted average exercise price of $1.39 per share and have expiration date on January 19, 2026. The Company cannot grant any additional awards under the 2012 Plan pursuant to its terms since more than 10 years have passed since its original adoption.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table sets forth, as of March 28, 2025, the number and percentage of outstanding shares of our common stock beneficially owned by: (a) each person who is known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock; (b) each of our directors; (c) each of our Named Executive Officers; and (d) all current directors and Named Executive Officers, as a group. As of March 28, 2025, there were 91,339,385 shares of common stock and no shares of preferred stock issued and outstanding.
Beneficial ownership has been determined in accordance with Rule 13d-3 under the Exchange Act. Under this rule, certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire shares (for example, upon exercise of an option or warrant or upon conversion of a convertible security) within 60 days of the date as of which the information is provided. In computing the percentage ownership of any person, the amount of shares is deemed to include the amount of shares beneficially owned by such person by reason of such acquisition rights. As a result, the percentage of outstanding shares of any person as shown in the following table does not necessarily reflect the person’s actual voting power at any particular date.
Beneficial ownership as set forth below is based on our review of our record stockholders list and public ownership reports filed by certain stockholders of the Company, and may not include certain securities held in brokerage accounts or beneficially owned by the stockholders described below.
To our knowledge, except as indicated in the footnotes to this table and pursuant to applicable community property laws, the persons named in the table have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them.
|
| Common Stock |
| |||||
|
| Number of Common Stock Shares Beneficially Owned (1) |
|
| Percent of Common Stock (1) |
| ||
Named Executive Officers and Directors |
|
|
|
|
|
| ||
Dr. Simon G. Kukes (2) |
|
| 59,736,275 |
|
|
| 65.4 | % |
J. Douglas Schick (3) |
|
| 1,577,133 |
|
|
| 1.7 | % |
Clark R. Moore (4) |
|
| 1,083,201 |
|
|
| 1.2 | % |
Paul A. Pinkston (5) |
|
| 816,700 |
|
| * |
| |
Jody D. Crook (6) |
|
| 364,118 |
|
| * |
| |
H. Douglas Evans (7) |
|
| 460,000 |
|
| * |
| |
John J. Scelfo (8) |
|
| 474,500 |
|
| * |
| |
|
|
|
|
|
|
|
|
|
All Named Executive Officers and Directors as a group (seven persons) |
|
| 64,511,927 |
|
|
| 70.6 | % |
|
|
|
|
|
|
|
|
|
Greater than 5% Stockholders |
|
|
|
|
|
|
|
|
The SGK 2018 Revocable Trust (8) |
|
| 51,791,325 |
|
|
| 56.7 | % |
*Less than 1%.
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Unless otherwise stated, the address of each stockholder is c/o PEDEVCO Corp., 575 N. Dairy Ashford, Suite 210, Houston, Texas 77079.
| (1) | Ownership voting percentages are based on 91,339,385 total shares of common stock which were outstanding as of March 28, 2025. |
|
|
|
| (2) | Consisting of the following: (a) 51,791,325 shares of common stock held by The SGK 2018 Revocable Trust, a family trust of which Dr. Kukes is the trustee, beneficiary and which Dr. Kukes is deemed to beneficially own; (b) 7,071,949 shares of fully-vested common stock held by Dr. Kukes; (c) 850,001 unvested shares of common stock held by Dr. Kukes, 133,334 of which vest on January 23, 2026, 183,333 of which vest on January 26, 2026, 183,334 of which vest on January 26, 2027, 116,666 of which vest on November 23, 2025, and 116,667 of which vest on each of November 23, 2026 and November 23, 2027, provided that Dr. Kukes remains employed by us, or is a consultant to us, on such vesting dates; (d) 3,000 shares of fully vested common stock held by the spouse of Dr. Kukes; and (e) options to purchase 20,000 shares of common stock exercisable by the spouse of Dr. Kukes at exercises price of $1.39 and $1.17 per share (options to purchase 10,000 shares of common stock each). Dr. Kukes has voting control over his unvested shares of common stock. |
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|
|
| (3) | Consisting of the following: (a) 610,466 shares of fully-vested common stock held by Mr. Schick; and (b) 966,667 unvested shares of common stock held by Mr. Schick, 116,667 which vest on January 23, 2026, 175,000 of which vest on each of January 26, 2026 and January 26, 2027, 166,666 of which vest on November 23, 2025, and 166,667 of which vest on each of November 23, 2026 and November 23, 2027, in each case provided that Mr. Schick remains employed by us, or is a consultant to us, on such vesting dates. Mr. Schick has voting control over his unvested shares of common stock. |
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|
|
| (4) | Consisting of the following: (a) 330,334 shares of fully-vested common stock held by Mr. Moore; (b) 2,867 fully-vested shares of common stock held by Mr. Moore’s minor child, which he is deemed to beneficially own; and (c) 750,000 unvested shares of common stock held by Mr. Moore, 100,000 of which vest on January 23, 2026, 150,000 of which vest on each of January 26, 2026 and January 26, 2027, 116,666 of which vest on November 23, 2025, and 116,667 of which vest on each of November 23, 2026 and November 23, 2027, in each case provided that Mr. Moore remains employed by us, or is a consultant to us, on such vesting dates. Mr. Moore has voting control over his unvested shares of common stock. |
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|
|
| (5) | Consisting of the following: (a) 393,366 shares of fully-vested common stock held by Mr. Pinkston; and (b) 423,334 unvested shares of common stock, 66,667 of which vest on January 23, 2026, 83,333 of which vest on January 26, 2026, and 83,334 of which vest on January 26, 2027, 63,333 of which vest on each of November 23, 2025 and November 23, 2026, and 63,334 of which vest on November 23, 2027, in each case provided that Mr. Pinkston remains employed by us, or is a consultant to us, on such vesting dates. Mr. Pinkston has voting control over his unvested shares of common stock. |
|
|
|
| (6) | Consisting of the following: (a) 23,333, shares of fully-vested common stock held by Mr. Crook; and (b) 340,785 unvested shares of common stock, 23,333 of which vest on January 26, 2026, 23,334 of which vest on January 26, 2027, and 98,039 of which vest on each of November 23, 2025 and November 23, 2026, and 98,040 which vest on November 23, 2027, in each case provided that Mr. Crook remains employed by us, or is a consultant to us, on such vesting dates. Mr. Crook has voting control over his unvested shares of common stock. |
|
|
|
| (7) | Consisting of the following: (a) 375,000 shares of fully-vested common stock held by Mr. Evans; and (b) 85,000 unvested shares of common stock, which vest on September 27, 2025, provided that Mr. Evans remains a director, employee of, or consultant to us on such vesting date. Mr. Evans has voting control over his unvested shares of common stock. |
|
|
|
| (8) | Consisting of the following: (a) 349,500 shares of fully-vested common stock held by Mr. Scelfo; and (b) 125,000 unvested shares of common stock, which vest on July 12, 2025, provided that Mr. Scelfo remains a director, employee of, or consultant to us on such vesting date. Mr. Scelfo has voting control over his unvested shares of common stock. |
|
|
|
| (9) | Consisting of 51,791,325 shares of common stock held by The SGK 2018 Revocable Trust. The SGK 2018 Revocable Trust is a family trust of which Dr. Kukes is the trustee and beneficiary, and as such, Dr. Kukes is deemed to be the beneficial owner of the shares held by The SGK 2018 Revocable Trust. |
| 141 |
| Table of Contents |
Equity Compensation Plan Information
The following table sets forth information, as of December 31, 2024, with respect to our compensation plans under which common stock is authorized for issuance.
Plan Category |
| Number of securities to be issued upon exercise of outstanding options, warrants and rights (A) |
|
| Weighted-average exercise price of outstanding options, warrants and rights (B) |
|
| Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column A) (C) |
| |||
Equity compensation plans approved by stockholders (1) |
|
| 1,835,667 |
|
| $ | 1.12 |
|
|
| 6,545,000 | (2) |
Equity compensation plans not approved by stockholders |
|
| - |
|
|
|
|
|
|
| - |
|
Total |
|
| 1,835,667 |
|
| $ | 1.12 |
|
|
| 6,545,000 |
|
(1) | Consists of options to purchase 525,667 shares of common stock issued and outstanding under the PEDEVCO Corp. 2012 Amended and Restated Equity Incentive Plan and options to purchase 1,310,000 shares of common stock issued and outstanding under the PEDEVCO 2021 Equity Incentive Plan. |
(2) | Consists of 6,545,000 shares of common stock reserved and available for issuance under the PEDEVCO Corp. 2021 Equity Incentive Plan. Does not include shares of common stock available for issuance under the 2012 Plan or 2012 Pre-Merger Plan as the Company has determined that it can no longer issue awards thereunder. |
The Company’s equity compensation plans are discussed in greater detail above under “Item 11. Executive Compensation” - “Equity Incentive Plans”.
Changes in Control
The Company is not currently aware of any arrangements which may at a subsequent date result in a change of control of the Company.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Except as referenced below or otherwise disclosed above under “Item 11. Executive Compensation”, which information is incorporated by reference in this Item 13, there have been no transactions since January 1, 2023, and there is not currently any proposed transaction, in which the Company was or is to be a participant, where the amount involved exceeds the lesser of $120,000 or one percent of the average of the Company’s total assets at year-end for the last two completed fiscal years, and in which any officer, director, or any stockholder owning greater than five percent (5%) of our outstanding voting shares, nor any member of the above referenced individual’s immediate family, had or will have a direct or indirect material interest.
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| Table of Contents |
Related Transactions
Related party transactions are discussed in greater detail under “Item 8. Financial Statements and Supplementary Data” - “Note 11 – Shareholders’ Equity – Common Stock” and “Note 12 – Share-Based Compensation”, of this Annual Report on Form 10-K, all of which information and disclosures is incorporated by reference into this “Item 13. Certain Relationships and Related Transactions, and Director Independence”.
Review and Approval of Related Party Transactions
We have not adopted formal policies and procedures for the review, approval or ratification of transactions, such as those described above, with our executive officer(s), director(s) and significant stockholders, provided that it is our policy that any and all such transactions are presented and approved by the independent members of the Board of Directors (typically through an ad hoc committee formed solely for the purpose of approving each individual transaction), or the Audit Committee (which pursuant to the charter of the Audit Committee is tasked with reviewing and, if appropriate, approving proposed transactions between the Company and “related persons” as defined in Item 404 of SEC Regulation S-K, and developing policies and procedures for the review and approval of such transactions, provided that no such policies or procedures have been developed to date), or a majority of the board (with the interested parties abstaining) and future material transactions between us and members of management or their affiliates shall be on terms no less favorable than those available from unaffiliated third parties.
In addition, our Code of Ethics (described above under “Item 10. Directors, Executive Officers and Corporate Governance” – “Code of Ethics”), which is applicable to all of our employees, officers and directors, requires that all employees, officers and directors avoid any conflict, or the appearance of a conflict, between an individual’s personal interests and our interests.
Director Independence
The Board annually determines the independence of each director and nominee for election as a director. The Board makes these determinations in accordance with the NYSE American’s listing standards for the independence of directors and the SEC’s rules.
In assessing director independence, the Board considers, among other matters, the nature and extent of any business relationships, including transactions conducted, between the Company and each director and between the Company and any organization for which one of our directors is a director or executive officer or with which one of our directors is otherwise affiliated.
Our Board has determined that Mr. Scelfo and Mr. Evans are independent directors as defined in the NYSE American rules governing members of boards of directors and as defined under Rule 10A-3 of the Exchange Act. Accordingly, 50% of the members of our Board are independent as defined in the NYSE American rules governing members of boards of directors and as defined under Rule 10A-3 of the Exchange Act.
Furthermore, the Board has determined that each of the members of our Audit Committee, Compensation Committee, and Nominating and Corporate Governance Committee is independent within the meaning of NYSE American director independence standards applicable to members of such committees, as currently in effect.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Our independent public accounting firm is Marcum LLP, Houston, Texas, PCAOB Auditor ID 688.
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| Table of Contents |
The following table presents fees for professional audit services performed by Marcum LLP for the audit of our annual financial statements for the years ended December 31, 2024 and 2023 (in thousands).
|
| 2024 |
|
| 2023 |
| ||
Audit Fees (1) |
| $ | 200 |
|
| $ | 239 |
|
Audit-Related Fees (2) |
|
| - |
|
|
| - |
|
Tax Fees (3) |
|
| 53 |
|
|
| 53 |
|
All Other Fees (4) |
|
| 67 |
|
|
| 48 |
|
Total |
| $ | 320 |
|
| $ | 340 |
|
(1) | Audit fees include professional services rendered for (1) the audit of our annual financial statements for the fiscal years ended December 31, 2024 and 2023 and (ii) the reviews of the financial statements included in our quarterly reports on Form 10-Q for such years. |
(2) | Audit-related fees consist of fees billed for professional services that are reasonably related to the performance of the audit or review of our consolidated financial statements but are not reported under “Audit fees.” |
(3) | Tax fees include professional services relating to preparation of the annual tax return. |
(4) | Other fees include professional services for review of various filings and issuance of consents. |
Pre-Approval Policies
It is the policy of our Board of Directors that all services to be provided by our independent registered public accounting firm, including audit services and permitted audit-related and non-audit services, must be pre-approved by our Board of Directors. Our Board of Directors pre-approved all services, audit and non-audit, provided to us by Marcum LLP for 2024 and 2023.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENTS
(1) Financial Statements
INDEX TO FINANCIAL STATEMENTS
Audited Financial Statements for Years Ended December 31, 2024 and 2023 |
|
|
|
PEDEVCO Corp.: |
|
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 688) | 86 |
Consolidated Balance Sheets as of December 31, 2024 and 2023 | 87 |
Consolidated Statements of Operations for the Years Ended December 31, 2024 and 2023 | 88 |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024 and 2023 | 89 |
90 | |
91 |
(2) Financial Statement Schedules
All financial statement schedules have been omitted, since the required information is not applicable or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and notes thereto included in this Form 10-K.
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(3) Exhibits required by Item 601 of Regulation S-K
|
|
|
|
|
| Incorporated By Reference | |||||||||||||||||
Exhibit |
|
| Filed or furnished With This Annual Report on |
|
|
| Filing Date/Period |
| File | ||||||||||||||
No. |
| Description |
| Form 10-K |
| Form |
| Exhibit |
| End Date |
| Number | |||||||||||
| 8-K | 1.1 | 12/20/2024 | 001-35922 | |||||||||||||||||||
|
|
| 8-K |
| 3.1 |
| 8/2/2012 |
| 000-53725 | ||||||||||||||
Certificate of Amendment of Amended and Restated Certificate of Formation |
| 8-K | 3.1 | 4/23/2013 | 000-53725 | ||||||||||||||||||
|
|
| 8-K |
| 3.1 |
| 2/24/2015 |
| 001-35922 | ||||||||||||||
Certificate of Amendment to Certificate of Formation (1-for-10 Reverse Stock Split of Common Stock) |
| 8-K | 3.1 | 3/27/2017 | 333-64122 | ||||||||||||||||||
|
|
| 8-K |
| 3.1 |
| 6/26/2018 |
| 001-35922 | ||||||||||||||
Bylaws of PEDEVCO Corp. (formerly Blast Energy Services, Inc.) |
| 8-K | 3.3 | 3/6/2008 | 333-64122 | ||||||||||||||||||
|
|
| 8-K |
| 3.1 |
| 12/6/2012 |
| 000-53725 | ||||||||||||||
| 8-K | 3.1 | 10/21/2016 | 001-35922 | |||||||||||||||||||
|
|
| 8-K |
| 3.1 |
| 8/26/2022 |
| 001-35922 | ||||||||||||||
| 10-K | 4.1 | 3/30/2020 | 001-35922 | |||||||||||||||||||
|
|
| S-3 |
| 4.1 |
| 10/23/2013 |
| 333-191869 | ||||||||||||||
PEDEVCO Corp. 2012 Equity Incentive Plan - Form of Restricted Shares Grant Agreement ** |
| S-8 | 4.2 | 10/31/2013 | 333-192002 | ||||||||||||||||||
| PEDEVCO Corp. 2012 Equity Incentive Plan - Form of Stock Option Agreement ** |
|
| S-8 |
| 4.3 |
| 10/31/2013 |
| 333-192002 | |||||||||||||
| 10-K | 10.11 | 3/31/2014 | 001-35922 | |||||||||||||||||||
|
|
| 10-K |
| 10.2 |
| 3/31/2014 |
| 001-35922 | ||||||||||||||
| 10-K | 10.43 | 3/31/2014 | 001-35922 | |||||||||||||||||||
|
|
| 10-K |
| 10.44 |
| 3/31/2014 |
| 001-35922 | ||||||||||||||
| 10-K | 10.58 | 3/31/2014 | 001-35922 | |||||||||||||||||||
| Offer Letter with J. Douglas Schick as President dated August 1, 2018** |
|
| 8-K |
| 10.4 |
| 8/1/2018 |
| 001-35922 | |||||||||||||
Offer Letter with Paul A. Pinkston as Chief Accounting Officer, dated October 16, 2018** |
| 8-K | 10.1 | 12/3/2018 | 001-35922 | ||||||||||||||||||
| PEDEVCO Corp. 2012 Amended and Restated Equity Incentive Plan** |
|
| S-8 |
| 4.1 |
| 8/29/2019 |
| 333-233525 | |||||||||||||
| 8-K | 10.3 | 3/31/2020 | 001-35922 | |||||||||||||||||||
|
|
| 8-K |
| 10.5 |
| 3/31/2020 |
| 001-35922 | ||||||||||||||
| 8-K | 10.1 | 9/1/2021 | 001-35922 | |||||||||||||||||||
| PEDEVCO Corp. 2021 Equity Incentive Plan Form of Restricted Shares Grant Agreement** |
|
| S-8 |
| 99.3 |
| 9/1/2021 |
| 333-259248 | |||||||||||||
PEDEVCO Corp. 2021 Equity Incentive Plan Form of Stock Option Grant Agreement** |
| S-8 | 99.2 | 9/1/2021 | 333-259248 | ||||||||||||||||||
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| Table of Contents |
| Amendment No. 3 to Employment Agreement between PEDEVCO Corp. and Clark R. Moore** |
|
| 8-K |
| 10.4 |
| 1/27/2022 |
| 001-35922 | |||||||||||||
| 8-K | 10.1 | 9/13/2023 | 001-35922 | |||||||||||||||||||
| 8-K | 10.1 | 11/9/2023 | 001-35922 | |||||||||||||||||||
Promissory Note dated November 9, 2023, executed by Tilloo Exploration and Production, LLC |
| 8-K | 10.2 | 11/9/2023 | 001-35922 | ||||||||||||||||||
| 8-K | 10.3 | 11/9/2023 | 001-35922 | |||||||||||||||||||
| 8-K | 10.4 | 11/9/2023 | 001-35922 | |||||||||||||||||||
| 8-K | 10.5 | 11/9/2023 | 001-35922 | |||||||||||||||||||
| First Amendment to PEDEVCO Corp. 2021 Equity Incentive Plan** |
|
|
| 8-K |
| 10.1 |
| 8/30/2024 |
| 001-35922 | ||||||||||||
|
|
|
| 8-K |
| 10.1 |
| 9/11/2024 |
| 001-35922 | |||||||||||||
|
|
|
| 8-K |
| 10.3 |
| 12/11/2024 |
| 001-35922 | |||||||||||||
|
|
|
| 8-K |
| 10.4 |
| 12/11/2024 |
| 001-35922 | |||||||||||||
|
|
|
| 8-K/A |
| 14.1 |
| 8/8/2012 |
| 000-53725 | |||||||||||||
| PEDEVCO Corp. First Amended and Restated Policy on Insider Trading** |
| X |
|
|
|
|
|
|
|
| ||||||||||||
|
| X |
|
|
|
|
|
|
|
| |||||||||||||
|
| X |
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|
|
|
|
|
|
| |||||||||||||
|
| X |
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|
|
|
|
|
|
| |||||||||||||
| Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| X |
|
|
|
|
|
|
|
| ||||||||||||
| Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| X |
|
|
|
|
|
|
|
| ||||||||||||
|
| * |
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|
|
|
|
| |||||||||||||
|
| * |
|
|
|
|
|
|
|
| |||||||||||||
97.1 |
| PEDEVCO Corp., Policy for the Recovery of Erroneously Awarded Incentive-Based Compensation ** |
|
|
| 10-Q |
| 10.2 |
| 11/9/2023 |
| 001-35922 | |||||||||||
|
| X |
|
|
|
|
|
|
|
| |||||||||||||
| Charter of the Nominating and Corporate Governance Committee |
|
|
| 8-K |
| 99.1 |
| 9/5/2013 |
| 001-35922 | ||||||||||||
|
|
|
| 8-K |
| 99.2 |
| 9/5/2013 |
| 001-35922 | |||||||||||||
|
|
|
| 8-K |
| 99.3 |
| 9/5/2013 |
| 001-35922 | |||||||||||||
101.INS |
| Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| X |
|
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| |||||||||||
101.SCH |
| XBRL Taxonomy Extension Schema Document |
| X |
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| |||||||||||
101.CAL |
| XBRL Taxonomy Extension Calculation Linkbase Document |
| X |
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| |||||||||||
101.DEF |
| XBRL Taxonomy Extension Definition Linkbase Document |
| X |
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| |||||||||||
101.LAB |
| XBRL Taxonomy Extension Label Linkbase Document |
| X |
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| |||||||||||
101.PRE |
| XBRL Taxonomy Extension Presentation Linkbase Document |
| X |
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| |||||||||||
104 |
| Inline XBRL for the cover page of this Annual Report on Form 10-K, included in the Exhibit 101 Inline XBRL Document Set. |
| X |
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| |||||||||||
X | Filed herewith. |
* | Furnished herein. |
** | Indicates management contract or compensatory plan or arrangement. |
# Certain schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished supplementally to the Securities and Exchange Commission upon request; provided, however that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedule or exhibit so furnished.
| 147 |
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ITEM 16. FORM 10-K SUMMARY.
None.
| 148 |
| Table of Contents |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PEDEVCO Corp. | ||
|
|
|
|
March 31, 2025 | By: | /s/ J. Douglas Schick |
|
|
| J. Douglas Schick |
|
|
| President, Chief Executive Officer, and Director |
|
|
| (Principal Executive Officer) |
|
March 31, 2025 | By: | /s/ Paul A. Pinkston |
|
|
| Paul A. Pinkston |
|
|
| Chief Accounting Officer (Principal Financial and Accounting Officer) |
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
By: /s/ Dr. Simon G. Kukes | Executive Chairman and Director | March 31, 2025 | ||
Dr. Simon G. Kukes | ||||
By: /s/ J. Douglas Schick | President, Chief Executive Officer, and Director | March 31, 2025 | ||
Mr. J. Douglas Schick |
| (Principal Executive Officer) |
|
|
|
|
|
|
|
By: /s/ Paul A. Pinkston | Chief Accounting Officer | March 31, 2025 | ||
Paul A. Pinkston | (Principal Financial and Accounting Officer) | |||
By: /s/ John J. Scelfo | Director | March 31, 2025 | ||
John J. Scelfo |
| |||
| ||||
By: /s/ H. Douglas Evans | Director | March 31, 2025 | ||
H. Douglas Evans |
|
| 149 |