Primeenergy Resources Corp 10-K for FY2025
Primeenergy Resources Corp (PNRG)
About this 10-K
Primeenergy Resources Corp filed this 10-K on April 16, 2026, covering the fiscal year ended December 31, 2025 (FY2025).
Headline figures
Fiscal year ended December 31, 2025, as reported in this filing, compared with the same period a year earlier where the filing states it.
- Revenue
- $189.05M
- down 20.5% from $237.8M a year earlier
- Net income
- $26.31M
- down 52.5% from net income of $55.4M a year earlier
- Diluted EPS
- $10.86
- down 50.5% from $21.95 a year earlier
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
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TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period From to .
Commission File Number
(Exact name of registrant as specified in its charter)
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Registrant’s telephone number, including area code: (
Securities registered pursuant to Section 12(b) of the Act
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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 whether 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, 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.
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Large Accelerated Filer |
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Accelerated Filer |
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Smaller Reporting Company |
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Emerging growth 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 stock of the registrant held by non-affiliates, computed by reference to the closing price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter, was $. The number of shares outstanding of the registrant’s Common Stock, par value $0.10 per share, as of April 10, 2026, was
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s proxy statement to be furnished to stockholders in connection with its 2026 Annual Meeting of Stockholders to be held to be filed pursuant to Regulation 14A within 120 days after the fiscal year end of December 31, 2025, are incorporated by reference in Part III hereof.
TABLE OF CONTENTS
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PART I |
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Definitions of Certain Terms and Conventions Used Herein |
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Cautionary Statement Concerning Forward-Looking Statements |
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Item 1. |
Business |
5 |
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Item 1A. |
Risk Factors |
15 |
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Item 1B. |
Unresolved Staff Comments |
28 |
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Item 1C. |
Cybersecurity |
28 |
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Item 2. |
Properties |
30 |
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Item 3. |
Legal Proceedings |
35 |
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Item 4. |
Mine Safety Disclosures |
35 |
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PART II |
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Item 5. |
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
36 |
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Item 6. |
Reserved |
37 |
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Item 7. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
37 |
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Item 7A. |
Quantitative and Qualitative Disclosures About Market Risk |
41 |
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Item 8. |
Financial Statements and Supplementary Data |
42 |
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Item 9. |
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures |
42 |
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Item 9A. |
Controls and Procedures |
42 |
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Item 9B. |
Other Information |
44 |
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Item 9C. |
Disclosure Regarding Foreign Jurisdictions That Prevent Inspections |
44 |
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PART III |
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Item 10. |
Directors, Executive Officers and Corporate Governance |
45 |
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Item 11. |
Executive Compensation |
45 |
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Item 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
45 |
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Item 13. |
Certain Relationships and Related Transactions, and Director Independence |
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Item 14. |
Principal Accountant Fees and Services |
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PART IV |
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Item 15. |
Exhibits and Financial Statement Schedules |
46 |
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Item 16. |
Form 10-K Summary |
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SIGNATURES |
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FINANCIAL STATEMENTS: |
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Index to Consolidated Financial Statements |
F-1 |
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Definitions of Certain Terms and Conventions Used Herein
Within this Report, the following terms and conventions have specific meanings:
Measurements.
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“Bbl” means a standard barrel containing 42 United States gallons. |
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“BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid. |
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“BOEPD” means BOE per day. |
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“Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. |
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“MBbl” means one thousand Bbls. |
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“MBOE” means one thousand BOEs. |
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“Mcf” means one thousand cubic feet and is a measure of gas volume. |
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“MMcf” means one million cubic feet. |
Indices.
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“Brent” means Brent oil price, a major trading classification of light sweet oil that serves as a benchmark price for oil worldwide. |
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“WAHA” is a benchmark pricing hub for West Texas gas. |
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“WTI” means West Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil used as a benchmark in oil pricing. General terms and conventions. |
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“DD&A” means depletion, depreciation and amortization. |
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“ESG” means environmental, social and governance. |
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“GAAP” means accounting principles generally accepted in the United States of America. |
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“GHG” means greenhouse gases. |
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“LNG” means liquefied natural gas. |
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“NGLs” means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the gas stream; such liquids include ethane, propane, isobutane, normal butane and natural gasoline. |
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“NYMEX” means the New York Mercantile Exchange. |
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“OPEC” means the Organization of Petroleum Exporting Countries. |
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“PrimeEnergy” or the “Company” means PrimeEnergy Resources Corporation and its subsidiaries. |
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“Proved developed reserves” means reserves that can be expected to be recovered 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. |
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“Proved reserves” means those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. |
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The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
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In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. |
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Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. |
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Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. |
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Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
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“Proved undeveloped reserves” means 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. |
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Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
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Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
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Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. |
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“SEC” means the United States Securities and Exchange Commission. |
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“Standardized Measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a 10 percent discount rate. |
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“U.S.” means United States. |
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With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Company’s working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres. |
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“WASP” means weighted average sales price. |
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All currency amounts are expressed in U.S. dollars. |
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This information in this Annual Report on Form 10-K (this “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “models,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to the Company are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on PrimeEnergy Resources Corporation “The Company” current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. In addition, the Company may be subject to currently unforeseen risks that may have a material adverse effect on it.
These risks and uncertainties include, among other things, volatility of commodity prices; product supply and demand; the impact of armed conflict (including the ongoing conflicts in Ukraine and the Middle East) or political instability on economic activity and oil and gas supply and demand; competition; the ability to obtain drilling, environmental and other permits and the timing thereof; the effect of future regulatory or legislative actions on the Company or the industry in which it operates, including potential changes to tax rates or laws, new restrictions on development activities or potential changes in regulations limiting produced water disposal; the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms; potential liability resulting from pending or future litigation; the costs, including the potential impact of cost increases due to inflation and supply chain disruptions, and results of development and operating activities; the impact of a widespread outbreak of an illness on global and U.S. economic activity, oil and gas demand, and global and U.S. supply chains; availability of equipment, services, resources and personnel required to perform the Company’s development and operating activities; access to and availability of transportation, processing, fractionation, refining, storage and export facilities; the Company’s ability to replace reserves, implement its business plans or complete its development activities as scheduled; the Company’s ability to achieve its emissions reductions, flaring and other sustainability goals; access to and cost of capital; the financial strength of (i) counterparties to the Company’s credit facility and derivative contracts, (ii) issuers of the Company’s investment securities and (iii) purchasers of the Company’s oil, NGL and gas production and downstream sales of purchased commodities; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying forecasts, including forecasts of production, operating cash flow, well costs, capital expenditures, rates of return, expenses, and cash flow from downstream purchases and sales of oil and gas, net of firm transportation commitments; quality of technical data; environmental and weather risks, including the possible impacts of climate change on the Company’s operations and demand for its products; cybersecurity risks; the risks associated with the ownership and operation of the Company’s well services business and acts of war or terrorism. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it.
Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Part I, Item 1. Business — Competition,” “Part I, Item 1. Business —Regulation,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in this Report for a description of various factors that could materially affect the ability of to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.
PrimeEnergy Resources Corporation
FORM 10-K ANNUAL REPORT
For the Fiscal Year Ended
December 31, 2025
PART I
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Item 1. |
BUSINESS. |
General
PrimeEnergy Resources Corporation (the “Company”) was organized in March 1973, under the laws of the State of Delaware. We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, and Oklahoma. All of our oil and gas properties and interests are located in the United States. Through our subsidiaries Prime Operating Company and EOWS Midland Company, we act as operator and provide well-servicing support operations for many of the onshore oil and gas wells we operate, as well as for third parties. We are also active in the acquisition of producing oil and gas properties through joint ventures with industry partners. In addition, we own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia. We are currently not receiving revenue from this asset, as development has not begun. In addition, through a wholly owned offshore company, we own a currently idle 60-mile-long pipeline offshore on the shallow shelf of Texas.
Additional Information
PrimeEnergy files or furnishes annual, quarterly, and current reports, proxy statements, and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). The SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including PrimeEnergy, that file electronically with the SEC.
The Company makes available, free of charge, through its website (www.primeenergy.com) its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC. In addition to the reports filed or furnished with the SEC, the Company publicly discloses information from time to time in its press releases. Such information, including information posted on or connected to the Company’s website, is not a part of, or incorporated by reference in, this Report or any other document the Company files with or furnishes to the SEC.
Information contained on the Company’s website is not part of or incorporated into this Report or any other filings with the SEC.
Exploration, Development, and Recent Activities
The Company’s goal is to responsibly develop its oil and gas reserves, predominantly through horizontal drilling. Our strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment. We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2026, we plan to continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our capital budget for the year is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.
Horizontal development of our leasehold acreage has continued at a fast pace, particularly in West Texas, where in 2025 we participated with Double Eagle, and Vital in the drilling and completion of 23 new horizontal wells targeting the Wolfcamp and Spraberry producing intervals. There are at least six pay intervals (“benches”) being developed in the Midland Basin, from the deeper Wolfcamp “D” up through the shallower Middle Spraberry. The economic variability from one area to another and from one well to another depends on geologic properties (thickness, porosity, permeability, and hydrocarbon maturity), lateral length, stimulation, and oil price, as well as the economies of scale and therefore cost advantages often achieved by the more active operators. Under our leasehold acreage in the Midland Basin, several of these benches have either never been tested, or not yet developed, however, near our acreage, some of these benches have just recently been aggressively developed. We estimate that our acreage in Reagan, Upton, and Martin counties has the potential for as many as 100 drilling locations for these benches that we believe will likely be drilled in the next several years. In particular, under our large acreage position in Reagan County, only the Wolfcamp “A” and “B” intervals have been developed so far, along with a one-well test of the Wolfcamp “D” on one block.
In 2023, the Company completed 35 horizontal wells operated by five operators: 32 of these are located in West Texas and three in Oklahoma. In total, including the cost of facilities, the Company invested approximately $96 million, 99% of which was for wells in West Texas where we have been developing various proven pay intervals in the Wolfcamp and Spraberry formations. Below is a recap of our horizontal development activity in 2023.
In Reagan County, Texas we participated with Hibernia Energy II (Now Civitas) in ten 2-mile-long horizontals carrying 25% interest and investing $25.6 million. These ten wells on our “Brynn” tract began production in April 2023. Also in Reagan County in 2023, we participated with DE IV, LLC (Double Eagle) in 15 horizontals and invested approximately $34.8 million: five of these were 2-mile-long laterals on the “Prime East” tract that were placed on production in May 2023, in which we have nearly 50% interest, another six 2-mile-long laterals on the “Studley AV” tract that were brought on production in December 2023 in which we have 7% interest, and four 2.5-mile laterals on the “Studley CKO” tract that were completed in December 2023 in which we have 20% interest. These 25 Reagan County wells were all completed in 2023.
In Upton County, Texas, we participated for 50% interest in two 3-mile-long horizontals operated by Apache. These were brought into production in October 2023 and required an investment of approximately $17 million through completion of the wells and central facilities. In Martin County, Texas in 2023, we participated with ConocoPhillips for 20.8% interest in five 2.5-mile-long horizontal laterals, investing approximately $12 million. These five were completed and brought online in September 2023. Also in 2023, in Oklahoma, we joined Ovintiv USA, Inc. in the drilling of three 3-mile-long horizontals located in Canadian County with 2% interest and invested approximately $645,000.
In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County. In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing $37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our“Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000. Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,800. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals.
In addition to this activity, in June of 2024, we participated with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract. Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and invested approximately $36.3 million. In addition, in November of 2024, in Reagan County, we participated with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total invested roughly $23 million. Each of these 15 horizontals were on production as of May 2025 and the Company has invested approximately $59.3 million in these additional 21 horizontal wells.
In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; we participated for approximately 3.14% interest and invested $405,000, these wells were completed in May 2025. In the second and third quarters of 2025, we participated in fifteen new horizontals in the Midland Basin of West Texas: these 15 wells are operated by Double Eagle on our “Full House” tract in Reagan County in which the Company participated with approximately 27% interest and invested approximately $30.1 million. In addition to the Reagan County activity, the Company participated in eight “Horseshoe” wells in Midland County with Vital Energy. Drilling activity with these wells began in the second quarter and the wells were put on production during the fourth quarter of 2025. The company has an average of 8.2% interest in these eight wells and invested approximately $5.4 million. We also participated with Devon Energy Production on two "Evelyn" wells in Kingfisher County, Oklahoma; we participated with approximately 9.95% interest and $1.4 million. These wells were drilled in July 2025 and completed November 2025. In total in these 27 wells, we invested approximately $37.3 million.
The Company’s horizontal development activities in the last three years, can be summarized as follows: in 2023 we invested $96 million in 35 horizontals, in 2024 we invested $113 million in 48 horizontals, and in 2025, we invested $96 million in 48 horizontals. Therefore, in total, since January 2023 and through 2025, the Company will have invested roughly $305 million in horizontal development, primarily in the Midland Basin of West Texas. It is also noteworthy, that since the start of our horizontal development activities in 2012 the Company has invested over $435 million in horizontal drilling in the Midland Basin of West Texas, and $47 million in Oklahoma, predominantly in the Scoop/Stack Play.
Additional future drilling activity on our leasehold acreage in West Texas is expected over the next few years. In particular, based on activity west of our acreage in Reagan County, and a recent deep test by Double Eagle on our joint leasehold, we anticipate that proposals could be put forward in the future for the drilling of between 36 and 45 new horizontals that will target the Wolfcamp “D” pay zone in Reagan County, and perhaps an additional test well or two in one or more of the other undeveloped pay horizons. In this future activity, we have the potential to invest over $100 million. In addition, the Company has identified 37 horizontal locations across our acreage in Upton and Martin counties that could be drilled in this same time frame. These additional 37 wells will require an investment of approximately $87 million. In total, therefore, with the $100 million in Wolfcamp “D” development, plus $87 million in 37 additional near-term wells expected to occur in the 2026-2027 timeframe, we have the potential to invest approximately $187 million in horizontal drilling in West Texas over the next several years.
In West Texas and eastern New Mexico, we maintain an acreage position of approximately 16,838 gross (9,420 net) acres, 97.6% of which are located in Reagan, Upton, and Martin counties of Texas where our current West Texas horizontal drilling activities are focused. In addition to the wells currently being drilled or completed, we believe this acreage has the resource potential to support the drilling of as many as 100 future horizontal wells.
In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,015 net leasehold acres in the Scoop/Stack Play. Of this acreage, we believe 2,145 net leasehold acres hold significant additional resource potential that could support the drilling of as many as 34 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. Proposals may be received on the remaining 1,870 acres, however, rather than participate we may choose to sell the acreage or farm-out, receiving cash and retaining an over-riding royalty interest (ORRI). In past 4 years as to farm-out of our interest, we have Horizontal development with ORRI as follows; 11 wells in 2022, 3 wells in 2023, 16 wells in 2024 and 2 wells in 2025. Also in 2025, we participated with Ovintiv Mid-Continent in the drilling of two 2-mile- long horizontals in Canadian County, Oklahoma with 3.14% interest, investing roughly $405,000 through completion and with Devon Energy Production in the drilling of two 2-mile-long horizontals in Kingfisher County, Oklahoma with 9.95% Interest and investing roughly $1,439,000. In 2026, we have plans to participate with Validus Energy II in the drilling of 1 3-mile long horizontal well in Grady County, Oklahoma with 3.47% interest, investing roughly $351,000 through completion, 1 well with Ovintiv Mid-Continent in the drilling of one 2.5-mile long horizontal in Garvin County, Oklahoma with 3.36% interest, investing roughly $291,000 through completion, and one 3-mile long horizontal in Garvin County, Oklahoma with a 2.27% interest, investing roughly $194,000 through completion.
Significant Activity
As of December 31, 2025, we had net capitalized costs related to proved oil and gas properties of $291 million. Total expenditures for the acquisition, exploration, and development of our properties during 2025 were $75 million as we continue development under the programs discussed above. Proved reserves as of December 31, 2025, were 28,388 MBOE which consisted of 82.3% proved developed reserves and 17.7% proved undeveloped reserves.
The Company participated in 21 horizontals in West Texas spud in the middle of 2024 that have been drilled in Spraberry and Wolfcamp producing intervals. In total, the Company invested an estimated $59.3 million in these 21 wells: Six operated by Apache, which were placed on production in March 2025 and the remaining 15, operated by Double Eagle, were on production in May 2025. In the second half of 2025, we participated in two development projects in West Texas with 8.2% interest in the drilling of eight wells in Midland County, operated by Vital Energy, and with 27% interest in 15 wells in Reagan County operated by Double Eagle. Total investment in these is estimated to be $35.5 million. In addition, during 2025, we participated in two horizontals developments in Oklahoma. In Canadian County with Ovintiv Mid- Continent we participated with 3.14% interest in two wells and invested approximately $405,000. In Kingfisher County, Oklahoma; we participated with approximately 9.95% interest and $1.4 million.
In 2025, the Company raised proceeds of $2.2 million from the sale of acreage, and commercial property
We believe that our diversified portfolio approach to our drilling activities produces more consistent and predictable economic results than would otherwise be experienced with a less diversified or higher-risk drilling program profile.
We attempt to assume the position of operator in all acquisitions of producing properties. We will continue to evaluate prospects for leasehold acquisition and exploration and development operations in areas in which we own interests and are actively pursuing the acquisition of producing properties. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income-producing assets to increase our net worth and increase our oil and gas reserve base.
We presently own producing and non-producing properties located primarily in Texas, and Oklahoma, and through a wholly owned subsidiary, we own a significant amount well-servicing equipment.
We do not own any refinery or marketing facilities and do not currently own or lease any bulk storage facilities other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems. All of our oil and gas properties and interests are located in the United States.
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In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of shut-ins and/or reduced takes of gas production during summer months. Prolonged shut-ins could result in reduced field operating income from properties in which we act as operator.
Exploration for oil and gas requires substantial expenditures, particularly in exploratory drilling in undeveloped areas, or “wildcat drilling.” As is customary in the oil and gas industry, substantially all of our exploration and development activities are conducted through joint drilling and operating agreements with others engaged in the oil and gas business.
Summaries of our oil and gas drilling activities, oil and gas production, and undeveloped leasehold, mineral, and royalty interests are set forth under Item 2., “Properties”, below. Summaries of our oil and gas reserves, future net revenue and present value of future net revenue are also set forth under Item 2., “Properties—Reserves”, below.
Well Operations
Our operations are conducted through our principal offices in Houston, Texas, and district offices in Houston and Midland, Texas, and Oklahoma City, Oklahoma. We currently operate 508 wells, including producing, saltwater disposal, injection, and supply wells: 30 through the Houston office, 323 through the Midland office, and 155 through the Oklahoma City office. We own a majority interest in nearly all of our operated wells.
We operate wells according to operating agreements that govern the relationship between us, as operator, and the other owners of working interests in the properties and joint venture participants. For each operated well, we receive monthly fees that are competitive in the areas of operations and we also are reimbursed for expenses incurred in connection with well operations.
Regulation
Regulation of the Oil and Natural Gas Industry
Our 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. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, 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 the United States Congress (“Congress”), state governments, the Federal Energy Regulatory Commission (the “FERC”) and other federal and state regulatory agencies and federal, state and local courts. We cannot predict when or whether any such proposals may become effective. We do not believe that such action or proposal would have a material disproportionate effect on us as compared to similarly situated competitors.
Regulation Affecting Production
Natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. In addition, 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 that may be drilled in an area and the unitization or pooling of crude 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 number of oil and natural gas wells we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. 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 natural 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. 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 for oil, natural gas and NGLs are not currently regulated in the United States and therefore are dictated by the prevailing market prices. Although prices of these energy commodities are currently unregulated, Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil and natural gas, or the prices charged for these commodities, might be proposed, what proposals, if any, might actually be enacted by 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 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, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take statutes 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.
To the extent that the Company enters into transportation contracts with pipelines that are subject to FERC regulation, the Company is subject to FERC requirements related to use of such capacity. Any failure on the Company’s part to comply with FERC’s regulations and policies related to pipeline transportation, reporting requirements or other regulations, and any failure to comply with a FERC-related pipeline’s tariff, could result in the imposition of civil and criminal penalties. In addition, any changes in FERC or state regulations or requirements on pipeline transportation may result in increased transportation costs on pipelines that are subject to such regulation, thereby negatively impacting the Company’s profitability.
Regulation of Environmental and Occupational Safety and Health Matters
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment and occupational health and safety. These laws and regulations may, among other things: (i) require the acquisition of permits to conduct exploration, drilling and production operations; (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; and (v) 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 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. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
The clear trend in environmental regulation has been 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 waste handling, storage, transportation, 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 purchasers. 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. While compliance with existing environmental laws and regulations has not had a material adverse effect on our operations to date, we can provide no assurance that this will continue in the future.
The following is a summary of the more significant existing and proposed environmental, occupational health and safety laws and regulations to which our business operations are or may be subject to and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
The Resource Conservation and Recovery Act
The 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 U.S. Environmental Protection Agency (the “EPA”), individual state governments administer some or all of the provisions of 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 crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. 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. A change in the classification of exploration and production wastes has the potential to significantly increase our waste disposal costs to manage, which in turn will result in increased operating costs and could adversely impact our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes 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. 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. Despite the “petroleum exclusion” of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we currently own, 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 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 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 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 and local laws. Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including wetland areas, is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers (the “USACE”) or an analogous state agency. In September 2015, the EPA and the USACE issued a final rule outlining federal jurisdictional reach under the CWA over waters of the U.S., including wetlands, which has since been subject to several revisions. In May 2023, the Supreme Court decided Sackett v. EPA, which significantly narrowed the scope of “waters of the United States.” Under Sackett, the jurisdictional “waters” refers only to “those relatively permanent, standing or continuously flowing bodies of water forming geographic features that are described in ordinary parlance as streams, oceans, rivers, and lakes” and to “wetlands that are as a practical matter indistinguishable from waters of the United States.” In August 2023, the EPA finalized a rule amending the definition of “waters of the United States” to conform with the recent Supreme Court decision in Sackett. Litigation challenging the EPA’s rule and aspects of the January 2023 definition not addressed by Sackett is ongoing. To the extent future changes expand the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. We do not expect the costs to comply with the requirements of the CWA to have a material adverse effect on our operations.
The Oil Pollution Act of 1990 amends the CWA and establishes strict liability for owners and operators of facilities that cause a release of oil into waters of the United States. In addition, this law requires owners and operators of facilities that store oil above specified threshold amounts to develop and implement spill prevention, control and countermeasures plans.
Safe Drinking Water Act and Saltwater Disposal Wells
In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled or otherwise disposed of on the lease may be sent to saltwater disposal wells for injection into subsurface formations. Underground injection operations are regulated under the federal Safe Drinking Water Act and permitting and enforcement authority may be delegated to state governments. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injection well operations. In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations.
Air Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard for ozone from 75 to 70 parts per billion. The EPA approved final attainment/nonattainment designations with the new ozone standards in July 2018 and currently all of the areas in which we operate are in attainment with such standards. However, state implementation of these revised air quality standards or a change in the attainment status of the areas in which we operate could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant.
Separately, in June 2016, the EPA finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. The EPA has also adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels.
Given the long-term trend toward increasing regulation, these and future laws and air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. We do not believe that compliance with such requirements, however, will have a material adverse effect on our operations.
Regulation of Greenhouse Gas Emissions
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) endanger public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for these emissions. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operations. In December 2023, the EPA finalized New Source Performance Standard (“NSPS”) Subpart OOOOb, which seeks to reduce methane and volatile organic compound emissions from the oil and natural gas source category and NSPS Subpart OOOOc, which create, for the first-time, emission guidelines for existing oil and natural gas sources that would be included in individual states’ implementation plans. These standards expand upon previously issued NSPS Subparts OOOO and OOOOa published by the EPA in 2012 and 2016, respectively. President Trump’s Administration is expected to continue to promulgate new or amended regulations that are supportive of oil and natural gas development.
Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events; if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
Hydraulic Fracturing Activities
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. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, resulting in new legislative and regulatory initiatives that seek to increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. Further, the EPA finalized regulations under the CWA in June 2016 that prohibit wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Also, the federal Bureau of Land Management (“BLM”) published a final rule in 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands; however, the BLM rescinded the 2015 rule in 2017.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities, or prohibit hydraulic fracturing or high volume hydraulic fracturing altogether. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of, or prohibiting, drilling or hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we may be required to incur 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.
If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.
Endangered Species Act and Migratory Birds
The federal Endangered Species Act (“ESA”) and (in some cases) 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’ habitat. 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 and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a 2011 settlement agreement, the FWS was required to make a determination on listing of more than 250 species as endangered or threatened under the FSA by no later than completion of the agency’s 2017 fiscal year. The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. In 2023, Recently, the FWS proposed that the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, be listed as endangered under the ESA. The designation as threatened or endangered of previously unprotected species in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our development and production activities that could have a material adverse impact on our ability to develop and produce our reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
OSHA
We are subject to the requirements of the Occupational Safety and Health Administration (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.
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, in certain cases, can delay or halt projects and cease production or operation of wells, pipelines and other operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.
Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2025, nor do we anticipate that such expenditures will be material in 2026.
Competition and Markets
The business of acquiring producing properties and non-producing leases suitable for exploration and development is highly competitive. Our competition, in our efforts to acquire both producing and non-producing properties, include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those available to us. Furthermore, domestic producers of oil and gas must not only compete with each other in marketing their output, but must also compete with producers of imported oil and gas and alternative energy sources such as coal, nuclear power and hydroelectric power. Competition among petroleum companies for favorable oil and gas properties and leases can be expected to increase. The Company also faces competition from companies that supply alternative sources of energy, such as wind, solar and other renewables. Competition will increase as alternative energy technology becomes more reliable and governments throughout the world support or mandate the use of such alternative energy,
The availability of a ready market for any oil and gas produced by us at acceptable prices per unit of production will depend upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the proximity of our producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels. There is no assurance that we will be able to market all of the oil or gas produced by us or that favorable prices can be obtained for the oil and gas production.
We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs.
We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production; however, hedging arrangements may expose us to risk of financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.
Oil and Gas Industry Considerations
Since the worldwide economic downturn in mid-2020, while oil prices have improved with demand steadily increasing, worldwide oil inventories, from a historical perspective, remain low. In addition, concerns exist with the ability of OPEC and other oil producing nations to meet forecasted future oil demand growth, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to their limited capital investments directed towards developing incremental oil supplies over the past few years. Furthermore, sanctions, import bans and price caps on Russia have been implemented by various countries in response to the ongoing war in Ukraine, further impacting global oil supply. In addition, threatened and actual closing of oil shipping routes, including the Strait of Hormuz, have significantly impacted global oil supply. As a result of these and other oil and gas supply constraints, the world has experienced significant increases in energy costs. In March 2025, OPEC and certain other oil-producing countries (“OPEC+”) announced a plan to start increasing crude oil output starting in April 2025, which includes the gradual unwinding beginning in April 2025 of OPEC’s MMBOPD production cut that started in July 2023. Economic volatility and geopolitical tensions have resulted in global supply chain disruptions, which has led to significant cost inflation. Global oil price levels and inflationary pressures will ultimately depend on various factors that are beyond the Company’s control, such as (i) the ability of OPEC and other oil producing nations to manage the global oil supply, (ii) the impact of sanctions, tariffs and import bans on production from Russia and other countries, (iii) the timing and supply impact of any Iranian sanction relief on their ability to export oil, (iv) the global supply chain constraints associated with manufacturing and distribution delays, (v) oilfield service demand and cost inflation, and (vi) political stability of oil consuming countries and oil producing regions. The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations.
Major Customers
The Company sells its oil and gas production to a number of direct purchasers under direct contracts or through other operators under joint operating agreements. Listed below are the percent of the Company’s total oil and gas sales made which represented more than 10% of the Company’s oil and gas sales in the year 2025.
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2025 |
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Oil: |
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DE Central Operating, LLC. |
53 | % | ||
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Civitas Resources Inc. |
12 | % | ||
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APA Corporation. |
18 | % | ||
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Natural gas and liquids: |
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DE Central Operating, LLC. |
40 | % | ||
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Civitas Resources Inc. |
26 | % | ||
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APA Corporation. |
15 | % | ||
Although there are no long-term purchasing agreements with these purchasers, we believe that they will continue to purchase our oil and gas products and, if not, could be readily replaced by other purchasers.
Employees
At December 31, 2025, we had 67 full time employees, 25 of whom were employed at our principal offices in Houston, Texas, at the offices of Prime Operating Company, and EOWS Midland Company, and 42 employees who were primarily involved in our district operations in Midland, Texas and Elmore City and Oklahoma City, Oklahoma.
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Item 1A. |
RISK FACTORS |
General Risk Factors
The prices of oil, NGL and gas are highly volatile. A sustained decline in these commodity prices could materially and adversely affect the Company’s business, financial condition and results of operations.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.39 per MMBTU in 2025 as compared to $2.13 per MMBTU in 2024, and have averaged $3.64 per MMBTU for the first four months of 2026. Oil prices, based on West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month prices, averaged $65.34 per barrel in 2025 as compared to $75.48 per barrel in 2024, and in the first three months of 2026, the first-of-the-month price has averaged $65.72 per barrel.
Any substantial or extended decline in future natural gas or crude oil prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in natural gas and crude oil prices may cause us to delay or postpone a significant portion of our exploration, development and exploitation projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility, and limit our ability to execute aspects of our business plans.
Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
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the level of consumer product demand; |
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the domestic and foreign supply of natural gas and oil |
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weather conditions and natural disasters; |
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political conditions in natural gas and oil producing regions, including the Middle East, Russia, Africa and South America; |
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actions by the members of the Organization of Petroleum Exporting Countries with respect to oil production levels and announcements of potential changes in such levels; |
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the price levels, including any changes to tariffs, and quantities of foreign imports to the United States; |
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actions of governmental authorities; |
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the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil; |
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inventory storage levels; |
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the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation; |
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the price, availability and acceptance of alternative fuels; |
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technological advances affecting energy consumption; |
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speculation by investors in oil and natural gas; |
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variations between product prices at sales points and applicable index prices; |
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conservation and environmental protection efforts, including activities by non-governmental organizations to restrict the exploration, development and production of natural gas and oil; |
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overall economic conditions; and |
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global or national health concerns, including the outbreak of pandemic or contagious disease. |
In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a noncash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, ongoing conflict in Ukraine and the Middle East, the occurrence or threat of terrorist attacks in the United States or other countries and global or national health concerns could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown. Concerns about global economic growth may have an adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition. These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas and oil prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease cash flow from operations and adversely affect our exploration and development activities.
We derive essentially all of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. Any delays in payments from such purchasers caused by their financial difficulties, including those resulting from continued volatility in both credit and commodity markets, will have an immediate negative effect on our results of operations and cash flows.
Additionally, 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 working interest owner, we could be required to pay the working interest owner’s share of the project costs.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We rely upon access to our revolving credit facility as a source of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.
Our debt agreements also require compliance with covenants to maintain specified financial ratios. If the price that we receive for our natural gas and oil production further deteriorates from current levels or continues for an extended period, it could lead to further reduced revenues, cash flow and earnings, which in turn could lead to a default under those ratios. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of decreased natural gas and oil prices or a further decline could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to reduce our capital expenditure plan, sell non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot assure you that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or not at all.
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, oil spills, GHG emissions, climate change or methane emissions and explosions of natural gas transmission lines, 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. 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 need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business. In addition, investors currently focused on the potential effectives of climate change may elect to shift some or all of their investments into non-fossil fuel energy related investments. Limitation of investments in and financings for fossil fuel energy could restrict the availability of capital, resulting in the restriction, delay, or cancellation of development and production activities.
We may not be insured against all of the operating risks to which we are exposed.
We maintain insurance coverage against certain, but not all, hazards that could arise from our operations. Such insurance is believed to be reasonable for the hazards and risks faced by us. We do not carry business interruption insurance. In addition, pollution and environmental risks are not fully insurable.
We maintain for our operations total excess liability insurance with limits of $20 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $100,000 per occurrence, subject to all terms, restrictions and sub-limits of the policies. We also maintain general liability insurance limits of $1 million per occurrence and $2 million in the aggregate.
We have several policies that cover environmental risks. We have environmental coverage under the per occurrence and aggregate limits of our general and umbrella liability policies (for a twelve-month term). These policies provide third-party surface cleanup, bodily injury and property damage coverage, and defense costs when a pollution event is sudden and accidental and is discovered within thirty days of commencement and reported to the insurance company within ninety days of discovery. This is standard coverage in oil and gas insurance policies.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers and contractors. However, customers and contractors who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
From time to time, a small number of our contractors have requested contractual provisions that require us to respond to third-party claims. In some of these instances we have accepted the risk with the understanding that it would be covered under our current coverage. We evaluate these risk-transferring negotiations cautiously, and we feel that we have adequately mitigated this risk through existing coverage or acquiring supplemental coverage when appropriate.
Terrorist activities and the potential for military and other actions could adversely affect our business.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. If there were insufficient capacity available on these facilities, if these facilities were unavailable to the Company or if access to these facilities were to become commercially unreasonable, the price offered for the Company's production could be significantly depressed, or the Company could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility or awaits the availability of third party facilities. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in order to gather, store, process, transport, fractionate, refine, export and sell its oil, NGL and gas production. The Company's plans to develop and sell production from its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient gathering, transportation, storage, processing, fractionation, refining or export facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist. Our failure to obtain these services on acceptable terms could materially harm our business.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
A failure of technology systems, data breach or cyber incident could materially affect our operations.
Our information technology systems may be vulnerable to security breaches, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information, including customer, employee, or other confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, cyber and other security threats are constantly evolving, thereby making it more difficult to successfully defend against them or to implement adequate preventative measures. The development and maintenance of these measures require continuous monitoring as technologies change and security measures evolve. We have experienced, and expect to continue to experience, cyber threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.
Information technology solution failures, network disruptions, breaches of data security and cyberattacks could disrupt our operations by causing delays, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A system failure, data security breach or cyberattack could have a material adverse effect on our financial condition, results of operations or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our e-mail systems, which to date have not had a material impact on our business; however, there is no assurance that such impacts will not be material in the future.
In addition to the risks presented to our systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets. Further, cyber-attacks on a communications network or power grid could cause operational disruption resulting in loss of revenues. A cyber-attack of this nature would be outside our control, but could have a material, adverse effect on our business, financial condition and results of operations.
Risks Related to our Business
The shut-in of our wells could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.
Our production depends, in part, upon our wells that are capable of commercial production not being shut-in (i.e., suspended from production). The lack of availability of capacity on third-party systems and facilities or the shut-in of an oil field’s production could result in the shut-in of our wells.
The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions. These curtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations.
If we experience low oil production volumes due to the shut-in of our wells or other mechanical failures or interruptions, it would impact our ability to generate cash flows from operations and we could experience a reduction in our available liquidity. A decrease in our liquidity could adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs.
Drilling natural gas and oil wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:
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decreases in natural gas and oil prices; |
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unexpected drilling conditions, pressure or irregularities in formations; |
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equipment failures or accidents; |
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adverse weather conditions; |
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loss of title or other title related issues; |
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surface access restrictions; |
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lack of available gathering or processing facilities or delays in the construction thereof; |
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lack of available capacity on interconnecting transmission pipelines; |
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lack of available drilling and production equipment or availability of oil field labor; |
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compliance with, or changes in, governmental requirements and regulation, including with respect to wastewater disposal, discharge of GHGs and fracturing; and |
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shortages or delays in the availability of required goods or services such as drilling rigs or crews, the delivery of equipment and the availability of sufficient water for drilling operations. |
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:
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the results of exploration efforts and the acquisition, review and analysis of the seismic data; |
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the availability of sufficient capital resources to us and the other participants for the drilling of the prospects; |
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the approval of the prospects by other participants after additional data has been compiled; |
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economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews; |
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our financial resources and results; and |
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the availability of leases and permits on reasonable terms for the prospects. |
These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.
Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.
Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
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the quality and quantity of available data; |
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the interpretation of that data; |
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the accuracy of various mandated economic assumptions; and |
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the judgment of the persons preparing the estimate. |
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (“FASB”) in Accounting Standards Codification (“ASC”) Section 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
The Company’s expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.
The Company has identified drilling locations and prospects for future drilling opportunities, including development and infill drilling activities. These drilling locations and prospects represent a significant part of the Company’s future drilling plans. The Company’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could adversely impact the Company’s ability to successfully complete those programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely impact the Company’s ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately meet the Company’s expectations for success. As such, the Company’s actual drilling activities may materially differ from the Company’s current expectations, which could have a significant adverse effect on the Company’s proved reserves, financial condition and results of operations.
Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.
In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves. In addition, there are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and the assumption of potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates.
We are continually identifying and evaluating opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.
The borrowing base under our revolving credit facility may be reduced in light of recent commodity price declines, which could limit us in the future.
The borrowing base under our revolving credit facility is currently $115 million, and lender commitments under our revolving credit facility are $300 million. The borrowing base is redetermined semi-annually under the terms of the revolving credit facility. In addition, either we or the lenders may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital markets to meet our obligations, including any such debt repayment obligations.
We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
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blowouts, cratering and explosions; |
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mechanical problems; |
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uncontrolled flows of natural gas, oil or well fluids; |
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formations with abnormal pressures; |
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pollution and other environmental risks; and |
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natural disasters. |
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities, other property or natural resources, clean-up responsibilities, regulatory investigations and penalties and suspension of operations.
The nature of the Company’s assets and production operations may impact the environment or cause environmental contamination, which could result in material liabilities to the Company.
The Company’s assets and production operations may give rise to significant environmental costs and liabilities as a result of the Company’s handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to its operations, and due to past industry operations and waste disposal practices. The Company’s oil and gas business involves the generation, handling, treatment, storage, transport and disposal of wastes, hazardous substances and petroleum hydrocarbons and is subject to environmental hazards, such as oil and produced water spills, NGL and gas leaks, pipeline and vessel ruptures and unauthorized discharges of such wastes, substances and hydrocarbons, that could expose the Company to substantial liability due to pollution and other environmental damage. For example, drilling fluids, produced waters and certain other wastes associated with the Company’s exploration, development and production of oil or gas are currently excluded under RCRA from the definition of hazardous waste. These wastes are instead regulated under RCRA’s less stringent non-hazardous waste provisions. There have been efforts from time to time to remove this exclusion. For example, in response to a federal consent decree issued in 2016, the EPA was required during 2019 to determine whether certain Subtitle D criteria regulations required revision in a manner that could result in oil and gas wastes being regulated as RCRA hazardous waste. In April 2019, the EPA made a determination that such revision of the regulations was unnecessary. Any future loss of the RCRA exclusion could have a material adverse effect on the Company’s results of operations and financial position.
The Company currently owns, leases or operates, and in the past has owned, leased or operated, properties that for many years have been used for oil and gas exploration and production activities, and petroleum hydrocarbons, hazardous substances and wastes may have been released on or under such properties, or on or under other locations, including off-site locations, where such substances have been taken for treatment or disposal. These wastes, substances and hydrocarbons may also be released during future operations. In addition, some of the Company’s properties have been operated by predecessors or previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company’s control. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons, hazardous substances and wastes on, under or from the Company’s properties. Private parties, including lessors of properties on which the Company operates and the owners or operators of properties adjacent to the Company’s operations and facilities where the Company’s petroleum hydrocarbons, hazardous substances or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as seek damages for noncompliance with environmental laws and regulations or for personal injury or damage to property or natural resources. Such properties and the substances disposed or released on or under them may be subject to CERCLA, RCRA and analogous state laws, which could require the Company to remove previously disposed substances, wastes and petroleum hydrocarbons, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination, the costs of which could have a material adverse effect on the Company’s business, financial condition and results of operations.
The Company may not be able to recover some or any of these costs from sources of contractual indemnity or insurance, as pollution and similar environmental risks generally are not insurable or fully insurable, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.
From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. These hedging arrangements limit the benefit to us of increases in prices. While there are many different types of derivatives available, we generally utilize put options and swap agreements to attempt to manage price risk more effectively.
The put options used to establish floor prices for a fixed volume of production during a certain time period. They provide for payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
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a counterparty is unable to satisfy its obligations |
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production is less than expected; or |
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there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production. |
The CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. While we believe that our use of swap transactions exempts us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
Legal and Regulatory Risks
Laws and regulations regarding hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions, delays or cancellations and have a material adverse effect on the Company’s production.
Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations. The Company conducts hydraulic fracturing in its drilling and completion programs. The process involves the injection of water, sand or other proppants and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions or similar agencies, but in recent years, several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and has issued guidance covering such activities. Moreover, the EPA has published an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing under the Toxic Substances Control Act and has implemented a final rule under the CWA prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly-owned wastewater treatment plants. Also, the BLM published a final rule in 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. The BLM rescinded the 2015 rule in late 2017; however, new or more stringent regulations may be promulgated in the future.
From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the additives used in the hydraulic-fracturing process. In addition, certain states, including Texas where the Company operates, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic-fracturing operations. For example, in April 2019, Colorado passed legislation reforming exploration and production activities by the oil and gas industry in the state including, among other things, revising the mission of the state oil and gas agency from fostering energy development in the state to instead focusing on regulating the industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties to regulate oil and gas operations within their jurisdictions as they do other development. While the Company does not conduct operations in Colorado, passage or enactment of similar legislation in other states in which it does operate could significantly increase the Company’s operating costs and have a significant adverse effect on the Company’s ability to conduct operations. In the absence of federal actions, states may elect to become more active in regulating or even could elect to prohibit hydraulic fracturing or high volume hydraulic fracturing altogether, following the approach taken by the states of Vermont, Maryland, Washington and New York. Also, local land use restrictions, such as city ordinances, may be adopted to restrict or prohibit drilling in general or hydraulic fracturing in particular. In Texas, legislation was adopted providing that the regulation of oil and gas operations in Texas is under the exclusive jurisdiction of the state and thus preempts local regulation of those operations. Nonetheless, municipalities and political subdivisions in Texas continue to have the right to enact “commercially reasonable” regulations for surface activities.
In the event federal, state or local restrictions or bans pertaining to hydraulic fracturing are adopted in areas where the Company is currently conducting operations, or in the future plans to conduct operations, the Company may incur additional costs to comply with such requirements, experience restrictions, delays or cancellations in the pursuit of exploration, development or production activities, and perhaps be limited or precluded in the drilling of wells or in the volume that the Company is ultimately able to produce from its reserves; one or more of which developments could have a material adverse effect on the Company.
The Company’s operations are subject to stringent environmental, oil and gas-related and occupational safety and health laws and regulations that could cause it to delay, curtail or cease its operations or expose it to material costs and liabilities.
The Company’s operations are subject to stringent federal, state and local laws and regulations governing, among other things, the drilling of wells, rates of production, the size and shape of drilling and spacing units or proration units, the transportation and sale of oil, NGL and gas, and the discharging of materials into the environment and environmental protection. For example, state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate development, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws (i) establish maximum rates of production from oil and gas wells, (ii) generally prohibit the venting or flaring of gas and (iii) impose requirements regarding production rates. These laws and regulations may limit the amount of oil and gas the Company can produce from the Company’s wells or limit the number of wells or the locations that the Company can drill.
In connection with its operations, the Company must obtain and maintain numerous environmental and oil and gas-related permits, approvals and certificates from various federal, state and local governmental authorities, and may incur substantial costs in doing so. The need to obtain permits has the potential to delay, curtail or cease the development of oil and gas projects. The Company may in the future be charged royalties on gas emissions or required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under standards to provide protection of public health and welfare. In subsequent years, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of the Company’s equipment, resulting in longer permitting timelines, and significantly increase the Company’s capital expenditures and operating costs. In another example, the EPA and U.S. Army Corps of Engineers (the “Corps”) released a final rule in 2015 outlining federal jurisdictional reach under the CWA over waters of the U.S., including wetlands, which has since been subject to several revisions. In August 2023, the EPA finalized a rule amending the definition of “waters of the United States” to conform with the recent Supreme Court decision in Sackett v. EPA. However, litigation challenging the EPA rulemaking and aspects of the January 2023 definition not addressed by Sackett is ongoing. To the extent that future changes to the definition expand the scope of the CWA’s jurisdiction in areas where the Company conducts operations, the Company could incur (i) delays, restrictions or prohibitions in the issuance of necessary permits, (ii) restrictions or cessations in the development or expansion of projects, or (iii) increases in the Company’s capital expenditures and operating expenses by, for example, requiring installation of new emission controls on some of the Company’s equipment, any one or more of which developments could have a material adverse effect on the Company’s business, financial condition and results of operations.
Additionally, the Company’s operations are subject to a number of federal and state laws and regulations, including the federal OSHA and comparable state statutes, whose purpose is to protect the health and safety of employees. Among other things, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens.
There can be no assurance that existing or future regulations will not result in a delay, curtailment or cessation of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or materially and adversely affect the Company’s future operations and financial condition. Noncompliance with these laws and regulations may subject the Company to sanctions, including administrative, civil or criminal penalties, remedial cleanups or corrective actions, delays in permitting or performance of projects, natural resource damages and other liabilities. Such laws and regulations may also affect the costs of acquisitions. In addition, these laws and regulations are subject to amendment or replacement in the future with more stringent legal requirements. Further, any delay, reduction or curtailment of the Company’s development and producing operations due to these laws and regulations could result in the loss of acreage through lease expiration.
The Company’s operations are subject to a number of risks arising out of concerns regarding the threat of climate change.
The Company’s operations are subject to a number of risks arising out of concerns regarding the threat of climate change, including regulatory and litigation risks, that could, among other things, result in increased operating costs and costs of compliance, limit the areas in which oil and gas production may occur, expose the Company to the risk of increased activism or reduce demand for the oil and gas the Company produces.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, (i) establish construction and operating permit reviews for GHG emissions from certain large stationary sources, (ii) require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources in the United States, (iii) implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and gas sector, and (iv) together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. For example, in December 2023, the EPA finalized NSPS Subpart OOOOb, which seeks to reduce methane and volatile organic compound emissions from the oil and natural gas source category and NSPS Subpart OOOOc, which create, for the first-time, emission guidelines for existing oil and natural gas sources that would be included in individual states’ implementation plans. These standards expand upon previously issued NSPS Subparts OOOO and OOOOa published by the EPA in 2012 and 2016, respectively. Additionally, various states, groups of states, and other countries have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is a non-binding agreement, the United Nations sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. In January 2025, the U.S. initiated the process of withdrawing from the Paris Agreement in January 2025 and completed its withdrawal in January 2026, after previously reentering it in February 2021. While the current U.S. administration could withdraw from or otherwise roll back existing GHG emissions regulations, it is not possible at this time to predict exactly which and to what extent such regulations will be modified, and how any such actions may impact our business. Further, such actions could prompt more activity from state and local legislative bodies and administrative agencies to pass stricter GHG emissions laws, regulations, and other binding commitments.
Litigation risks relating to GHG emissions and climate change are increasing, as a number of cities, local governments or other persons have sought to bring suit against oil and gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
The adoption and implementation of new or more stringent international, federal or state regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce oil and gas or generate GHG emissions could result in increased compliance and consumption costs, and thereby reduce demand for the oil and gas the Company produces. Additionally, political, litigation and financial risks could result in the restriction or cancellation of production activities, incurring liability for infrastructure damages as a result of climate change, or impairing the Company’s ability to continue to operate in an economic manner. Finally, if increasing concentrations of GHGs in the Earth’s atmosphere were to result in significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events, then such effects could have a material adverse effect on the Company’s exploration and production operations.
In addition, companies in the oil and gas industry have been the target of activist efforts from both individuals and non-governmental organizations, including instituting litigation and supporting political or regulatory efforts to, among other things, limit or ban hydraulic fracturing, restrict or ban certain operating practices, including the disposal of waste materials, such as hydraulic fracturing fluids and produced water, deny or delay drilling permits, prohibit the venting or flaring of gas, reduce access of the oil and gas industry to federal and state government lands, and delay or cancel oil and gas developmental or expansion projects. The Company may need to incur significant costs associated with responding to these initiatives, and complying with any resulting additional legal or regulatory requirements could have a material adverse effect on the Company’s business, financial condition, cash flows and results of operations.
Laws and regulations pertaining to protection of threatened and endangered species or to critical habitat, wetlands and natural resources could delay, restrict or prohibit the Company’s operations and cause it to incur substantial costs that may have a material adverse effect on the Company’s development and production of reserves.
The federal ESA and comparable state laws were established to protect endangered and threatened species. Under the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Federal Migratory Bird Treaty Act. Oil and gas operations in the Company’s operating areas may be adversely affected by seasonal or permanent restrictions imposed on drilling activities by the U.S. Fish and Wildlife Services (the “FWS”) that are designed to protect various wildlife, which may materially restrict the Company’s access to federal or private land use. Permanent restrictions imposed to protect endangered and threatened species could prohibit drilling in certain areas, impact suppliers of critical materials or services, or require the implementation of expensive mitigation measures. Additionally, federal statutes, including the CWA, the OPA and CERCLA, as well as comparable state laws, prohibit certain actions that adversely affect critical habitat, wetlands and natural resources. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling, construction or releases of petroleum hydrocarbons, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties.
Moreover, as a result of one or more settlements entered into by the FWS, the agency is required to make determinations on the potential listing of numerous species as endangered or threatened under the ESA. The designation of previously unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to incur increased costs arising from species protection measures or could result in delays, restrictions or prohibitions on its development and production activities that could have a material adverse effect on the Company’s ability to develop and produce reserves.
We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations.
It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.
Increasing scrutiny and changing expectations from investors, lenders and other market participants with respect to our Environmental, Social and Governance (“ESG”) policies may impose additional costs on us or expose us to additional risks.
Companies across all industries continue to face scrutiny relating to their ESG policies. Investor advocacy groups, certain institutional investors, investment funds, lenders and other market participants, often focus on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. At the same time, some stakeholders and regulators have increasingly expressed or pursued opposing views, legislation, and investment expectations with respect to ESG, including the enactment or proposal of “anti-ESG” legislation or policies. Our ESG practices and related disclosures may be subject to increased scrutiny and may not satisfy the requirements of all stakeholders or their requirements may not be made known to us. The increased focus and activism related to ESG and similar matters may hinder access to capital, as investors and lenders may decide to reallocate capital or not to commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor, lender or other industry shareholder expectations and standards, which are evolving and may be conflicting, or which are perceived to have not responded appropriately to such stakeholder’s concern, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition or stock price of such a company could be materially and adversely affected.
Additionally, certain investors and lenders have and may continue to exclude companies engaged in exploration and production activity, such as us, from their investing portfolios altogether due to ESG factors. These limitations in both the debt and equity capital markets may affect our ability to grow as our plans for growth may include accessing those markets. If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, or at all, we may be unable to implement our business strategy, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Further, we may incur additional costs and require additional resources to monitor, report and comply with ESG requirements that may be adopted. The occurrence of any of the foregoing could have a material adverse effect on our business and financial condition.
Changes to the U.S. federal tax laws could adversely affect our financial position, results of operations and cash flow.
Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally, or the interpretation or application thereof. From time to time, U.S. and foreign tax authorities, including state and local governments consider legislation that could increase our effective tax rate.
The IRS includes a 1% tax on publicly traded corporations on the fair market value of stock repurchased during any taxable year. Such tax applies to the extent such buybacks exceed $1 million during such year, which buyback value may be offset by other stock issuances.
Further, the U.S. Congress has advanced a variety of tax legislation proposals, and while the final form of any legislation is uncertain, the current proposals, if enacted, could have a material effect on our effective tax rate. Additionally, in recent years, lawmakers and the U.S. Department of the Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to; (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. This legislation or any future similar changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to natural gas and oil exploration and production, which could negatively affect our results of operations and financial condition.
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Item 1B. |
UNRESOLVED STAFF COMMENTS. |
We are a smaller reporting company and therefore no response is required pursuant to this Item.
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Item 1C. |
CYBERSECURITY |
As an oil and gas producer, the Company is dependent on digital technology in many areas of its business and operations. Additionally, the Company gathers and safeguards sensitive information as a part of its regular business activities. The Company continually evaluates and integrates new processes, systems and resources to enhance its defenses against cybersecurity threats.
Governance
Cybersecurity Program Management
Key aspects of the Company’s Cybersecurity Program include:
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Risk assessments designed to help identify material cybersecurity risks to critical systems and the company-wide information technology environment; |
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Continuous monitoring of Company systems and conducting periodic penetration tests; |
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An IRP that includes procedures for responding to cybersecurity incidents; |
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Required cybersecurity trainings for employees, incident response personnel, and management related to physical security of assets, data privacy and other information security policies and procedures; and |
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A third-party risk management process for its service providers, suppliers, vendors and other business associates. |
The Cybersecurity Program is integrated into the Company’s overall enterprise risk management process and shares common methodologies, reporting channels, and governance processes that apply across the enterprise risk management process to other legal, compliance, strategic, operational, and financial risk areas. Cyber risks identified in the overall enterprise risk management process are reviewed annually by the Executive Committee.
Risks from Cybersecurity Threat
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Item 2. |
PROPERTIES. |
Our executive offices, as well as offices of Prime Operating Company and EOWS Midland Company are located in leased premises in Houston, Texas.
We maintain district offices in Midland, Texas, and Oklahoma City, Oklahoma and have field offices in Midland, Texas, as well as, Garvin, Oklahoma.
Substantially all of our oil and gas properties are subject to a mortgage given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.
The information set forth below concerning our properties, activities, and oil and gas reserves includes our interests in affiliated entities.
The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the three years ended December 31, 2025.
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2025 |
2024 |
2023 |
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Gross |
Net |
Gross |
Net |
Gross |
Net |
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Exploratory: |
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Oil |
— | — | — | — | — | — | ||||||||||||||||||
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Gas |
— | — | — | — | — | — | ||||||||||||||||||
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Dry |
— | — | — | — | — | — | ||||||||||||||||||
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Development: |
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Oil |
27 | 4.9 | 59 | 18.74 | 35 | 8.37 | ||||||||||||||||||
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Gas |
— | — | — | — | — | — | ||||||||||||||||||
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Dry |
— | — | — | — | — | — | ||||||||||||||||||
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Total: |
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Oil |
27 | 4.9 | 59 | 18.74 | 35 | 8.37 | ||||||||||||||||||
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Gas |
— | — | — | — | — | — | ||||||||||||||||||
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Dry |
— | — | — | — | — | — | ||||||||||||||||||
| 27 | 4.9 | 59 | 18.74 | 35 | 8.37 | |||||||||||||||||||
Oil and Gas Production
As of December 31, 2025, we had ownership interest in the following number of gross and net producing oil and gas wells(1).
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Gross |
Net |
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Producing Wells(1) |
1,032 | 427 | ||||||
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(1) |
A gross well is a well in which a working interest is owned. A net well is the sum of the fractional working interests owned in gross wells. |
The following table shows our net production of oil, NGL and natural gas for each of the three years ended December 31, 2025. “Net” production is net after royalty interests of others are deducted and is determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold, mineral or royalty interest owned by us.
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2025 |
2024 |
2023 |
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Oil (barrels) |
2,286,000 | 2,556,000 | 1,144,000 | |||||||||
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NGL (barrels) |
1,650,000 | 1,284,000 | 606,000 | |||||||||
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Gas (Mcf) |
9,825,000 | 7,766,000 | 4,127,000 | |||||||||
The following table sets forth our average sales prices together with our average production costs per unit of production for the three years ended December 31, 2025.
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2025 |
2024 |
2023 |
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Average sales price per barrel of oil |
$ | 63.32 | $ | 75.80 | $ | 76.84 | ||||||
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Average sales price per barrel of NGL |
$ | 15.32 | $ | 20.25 | $ | 19.64 | ||||||
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Average sales price per Mcf of natural gas |
$ | 0.76 | $ | 0.43 | $ | 1.93 | ||||||
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Average production costs per net equivalent barrel of oil(1) |
$ | 8.07 | $ | 9.29 | $ | 12.98 | ||||||
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(1) |
Net equivalent barrels are computed at a rate of 6 Mcf per barrel and costs exclude production taxes. |
Acreage
The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold and mineral interests as of December 31, 2025. “Undeveloped acreage” is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
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Developed |
Undeveloped |
Total |
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Gross |
Net |
Gross |
Net |
Gross |
Net |
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Leasehold acreage |
81,510 | 24,561 | - | - | 81,510 | 24,561 | ||||||||||||||||||
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Mineral fee acreage |
1,640 | 117 | 19,257 | 417 | 20,987 | 534 | ||||||||||||||||||
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Total |
83,150 | 24,678 | 19,257 | 417 | 102,407 | 25,095 | ||||||||||||||||||
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 of December 31, 2025, is zero acres for the year ending December 31, 2026, zero acres in 2027, and zero acres in 2028.
Reserves
All of our interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2025. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our districts consist of degreed engineers with over twenty-five years of industry experience and between ten and twenty-five years of experience managing our reserves. Our Engineering manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, holds a Bachelor degree in Petroleum Engineering and has over thirty years of experience in the oil and gas industry.
See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:
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Reserve Category |
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Proved Developed |
Proved Undeveloped |
Total |
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As of December 31, |
Oil |
NGLs |
Gas |
Total |
Oil |
NGLs |
Gas |
Total |
Oil |
NGLs |
Gas |
Total |
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2023 |
5,757 | 3,676 | 24,749 | 13,558 | 6,254 | 5,156 | 24,470 | 15,488 | 12,011 | 8,832 | 49,219 | 29,046 | ||||||||||||||||||||||||||||||||||||
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2024 |
7,444 | 6,597 | 37,489 | 20,288 | 3,166 | 1,670 | 8,326 | 6,224 | 10,610 | 8,267 | 45,815 | 26,512 | ||||||||||||||||||||||||||||||||||||
| 2025 | 7,432 | 6,981 | 53,786 | 23,377 | 2,822 | 1,063 | 6,756 | 5,011 | 10,254 | 8,044 | 60,542 | 28,388 | ||||||||||||||||||||||||||||||||||||
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(a) |
In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil. |
In 2023, the Company partnered with four operators in the drilling of 57 horizontal wells: 54 of these located in West Texas and three located in Oklahoma. At year-end 2023, 23 of these wells had been completed and the remaining 34 were completed in 2024. In those wells completed in 2023 the Company invested approximately $42.8 million and in the 34 remaining West Texas wells completed in 2024, the total investment, including central facilities, was approximately $81.3 million. At year-end 2023, six of the 34 wells completed in 2024 were categorized as probable undeveloped, therefore, their non-proved reserves were not included in the reserve report that reported only proved reserves. At year-end 2023, the Company had 15,489 MBOE of proved undeveloped reserves attributable to 52 undeveloped wells, 42 of which were in the process of being drilled or completed at year-end.
In 2024, the Company invested $113 million in drilling and completion of 48 new horizontals in West Texas: 47 of these are located in Reagan County, and one is located in Upton County. In Reagan County, the Company joined Double Eagle in 33 new horizontals with an average 28.2% interest and invested approximately $66 million. Also in Reagan County, we participated with Civitas in 14 horizontals on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,700.
At year-end 2024, the Company participated in 21 horizontals in West Texas. Of these 21 wells, six are located in Upton County, operated by Apache Corporation; three of the six were completed by year-end and three were completed after the first of the year and all were brought online in May, 2025. The remaining 15 of the 21 wells, located on our “OG” tracts and operated by Double Eagle, were on production by September 2025. At year-end 2024, the Company had 6,224 MBOE of proved undeveloped reserves attributable to 33 undeveloped wells.
In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; we participated for approximately 3.14% interest and invested $405,000, these wells were completed in May 2025. In the second and third quarters of 2025, we participated in fifteen new horizontals in the Midland Basin of West Texas: these 15 wells are operated by Double Eagle on our “Full House” tract in Reagan County in which the Company participated with approximately 27% interest and invested approximately $30.1 million. In addition to the Reagan County activity, the company participated in eight “Horseshoe” wells in Midland County with Vital Energy. Drilling activity with these wells began in the second quarter and the wells were put on production during the fourth quarter of 2025. The company has an average of 8.2% interest in these eight wells and invested approximately $5.4 million. We also participated with Devon Energy Production on two "Evelyn" wells in Kingfisher County, Oklahoma; we participated with approximately 9.95% interest and $1.4 million. These wells were drilled in July 2025 and completed November 2025. In total in these 27 wells, we invested approximately $37.3 million.
At year-end 2025, the Company participated in 27 horizontals in West Texas and Oklahoma. Of these 27 wells, twenty three of the wells are located in West Texas and the remaining four in Oklahoma. The West Texas wells consisted of eight wells located in Midland County and 15 wells located in Reagan County. The four wells in Oklahoma were located in Canadian and Kingfisher Counties with each county having two wells. At year-end 2025, the Company had 5,011 MBOE of proved undeveloped reserves attributable to 37 undeveloped wells.
The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2025, are summarized as follows (in thousands of dollars):
|
Proved Developed |
Proved Undeveloped |
Total |
||||||||||||||||||||||||||||||
|
As of December 31, |
Future Net |
Present |
Future Net |
Present |
Future Net |
Present |
Present |
Standardized |
||||||||||||||||||||||||
|
2023 |
$ | 314,415 | $ | 213,281 | $ | 253,959 | $ | 138,679 | $ | 568,374 | $ | 351,960 | $ | 73,912 | $ | 278,048 | ||||||||||||||||
|
2024 |
$ | 389,266 | $ | 280,595 | $ | 111,451 | $ | 65,030 | $ | 500,716 | $ | 345,626 | $ | 72,581 | $ | 273,045 | ||||||||||||||||
|
2025 |
$ | 389,328 | $ | 268,440 | $ | 57,261 | $ | 20,405 | $ | 446,589 | $ | 288,845 | $ | 62,662 | $ | 226,183 | ||||||||||||||||
The PV10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.
“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are 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.
In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.
While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.
Natural gas prices, based on the twelve-month average of the first-of-the-month Henry Hub index price, were $3.39 per MMBtu in 2025 as compared to $2.13 per MMBtu in 2024 and $2.64 per MMBtu in 2023. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month average spot price, were $65.34 per barrel in 2025 as compared to $75.48 per barrel in 2024, and $78.22 per barrel in 2023. Since January 1, 2024, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.
District Information
The following table represents certain reserves and well information as of December 31, 2025.
|
Gulf |
Mid- |
West |
Other |
Total |
||||||||||||||||
|
Proved Reserves as of December 31, 2025 (MBoe) |
||||||||||||||||||||
|
Developed |
429 | 1,401 | 21,544 | 3 | 23,377 | |||||||||||||||
|
Undeveloped |
- | - | 5,011 | - | 5,011 | |||||||||||||||
|
Total |
429 | 1,401 | 26,555 | 3 | 28,388 | |||||||||||||||
|
Average Net Daily Production (Boe per day) |
161 | 962 | 14,152 | 3 | 15,278 | |||||||||||||||
|
Gross Productive Wells (Working Interest and ORRI Wells) |
96 | 677 | 791 | 72 | 1,636 | |||||||||||||||
|
Gross Productive Wells (Working Interest Only) |
67 | 362 | 592 | 11 | 1,032 | |||||||||||||||
|
Net Productive Wells (Working Interest Only) |
19 | 125 | 281 | 1 | 427 | |||||||||||||||
|
Gross Operated Productive Wells |
26 | 117 | 317 | - | 460 | |||||||||||||||
|
Gross Operated Water Disposal, Injection and Supply wells |
4 | 38 | 6 | - | 48 | |||||||||||||||
In West Texas, we have a field service group to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, saltwater disposal facilities, and trucks we own that are operated by our field employees.
Gulf Coast Region
Our production and development activities in the Gulf Coast region are concentrated in southeast and east Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, Hackberry, and Yegua formations at depths ranging from 6,000 to 12,000 feet. We had 96 producing wells (19 net) in the Gulf Coast region as of December 31, 2025, of which 26 wells are operated by us. Average net daily production in our Gulf Coast Region at year-end 2025 was 161Boe. At December 31, 2025, we had 429 MBoe of proved reserves in the Gulf Coast region, which represented 1,51% of our total proved reserves. We maintain an acreage position of over 7,003 gross (4,532 net) acres in this region, primarily in Colorado, Newton, and Polk counties.
We are monitoring the production from a new well drilled by Ventex Operating, on acreage in the Segno field of Polk County, Texas where the Company farmed-out its 55% leasehold rights for cash and a 5.53% over-riding royalty interest (ORRI). The well was cased in February 2025 and placed on production in May 2025. Currently, the well is producing 800 Mcfd and 32 Bopd.
The Gulf Coast region has plans to recomplete two producing wells: Sarah F. Wing #80 and the Sarah F. Wing #85 wells in the Segno field of Polk County, Texas, at an expense of approximately $300,000 in total. The Wing #16 was recompleted to the Wilcox A in 2025 at an approximate expense of $500,000. Gas lift valves have been installed with testing currently under way. Other than these recompletions, we currently have no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.
Mid-Continent Region
Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2025, we had 677 producing wells (125 net) in the Mid-Continent area, of which 117 wells are operated by us. Principal producing intervals are in the Robberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. The average net daily production in our Mid-Continent Region in 2025 was 962 Boe. On December 31, 2025, we had 1,401 MBoe of proved reserves in the Mid-Continent area, representing 4.94% of our total proved reserves. We maintain an acreage position of approximately 43,837 gross (10,062 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.
Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Scoop and Stack plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations. In Canadian County, Oklahoma, we have participated with Ovintiv Mid-Continent in the drilling of two 2-mile-long horizontal wells that was spud in early March 2025 and completed in May 2025. Our share of these wells is approximately 3.14% and the total investment is approximately $405,000. We also participated with Devon in Kingfisher County, Oklahoma to drill two 2-mile-long horizontal wells that were spud July 2025 and completed in November 2025. Our share of these wells is approximately 9.95% and total investment of approximately $1,439,000. In 2026, we have plans to participate with Validus Energy II in the drilling of one 3-mile long horizontal well in Grady County, Oklahoma with 3.47% interest, investing roughly $351,000 through completion, one well with Ovintiv Mid-Continent in the drilling of one 2.5-mile long horizontal in Garvin County, Oklahoma with 3.36% interest, investing roughly $291,000 through completion, and one 3-mile long horizontal in Garvin County, Oklahoma with a 2.27% interest, investing roughly $194,000 through completion.
West Texas Region
Our West Texas activities are concentrated in the Permian Basin in Texas. The oil and gas in this basin are produced primarily from five intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2025, we had 791wells (281 net) in the West Texas area, of which 317 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. The average net daily production in our West Texas Region at year-end 2025 was 14,152 Boe. On December 31, 2025, we had 21,544 MBoe of proved reserves in the West Texas area, or 93.54% of our total proved reserves. We maintain an acreage position of approximately 16,838 gross (9,420 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, three hot oiler trucks, and one kill truck. Oil field support is provided for drilling and workover operations both to third-party operators as well as for our own operated wells and locations.
During 2024, the Company participated with Double Eagle in the drilling or completion of 15 horizontal wells in Reagan County, Texas with an average of 23% interest, and participating with Apache Corporation in six wells in Upton County, Texas with 51.2% interest. In total, we spent approximately $59.3 million in these 21 horizontals and their associated facilities.
Future drilling activity on our leasehold acreage in West Texas is expected in the next few years as well. In particular, based on activity west of our acreage in Reagan County, and a recent deep test by Double Eagle on our joint leasehold, we anticipate that proposal could soon be put forward for the drilling of between 36 and 45 new horizontals that will target the Wolfcamp “D” pay zone in Reagan County and perhaps an additional test well or two in one or more of the other undeveloped pay horizons. In this future activity, we have the potential to invest in excess of $100 million. In addition, the Company has identified 37 horizontal locations across our acreage in Upton and Martin counties that could be drilled in this same time frame. These additional 37 wells will require an investment of approximately $87 million. In total, therefore, with the $100 million in Wolfcamp “D” development, and the $87 million in 37 other near-term wells expected in the 2026-2027 timeframe, we have the potential to invest approximately $187 million in horizontal drilling in West Texas over the next several years.
|
Item 3. |
LEGAL PROCEEDINGS. |
In the ordinary course of conducting our business, we become involved in litigation and other claims from private party actions, as well as judicial and administrative proceedings involving governmental authorities at the federal, state, and local levels. While the outcome of litigation or other proceedings against us cannot be predicted with certainty, management does not expect that any loss resulting from such litigation or other proceedings, in excess of any amounts accrued or covered by insurance, will have a material adverse impact on our consolidated financial statements.
|
Item 4. |
MINE SAFETY DISCLOSURES. |
Not applicable.
PART II—OTHER INFORMATION
|
Item 5. |
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. |
Our common stock is listed and principally traded on the Nasdaq Stock Market under the ticker symbol “PNRG”.
As of April 13, 2026 there were 176 registered holders of the common stock.
We have not paid any dividends during the three most recent fiscal years or any subsequent interim period, and we do not intend to pay any cash dividends in the foreseeable future. Provisions of our line of credit agreement restrict our ability to pay dividends. Such dividends may be declared out of funds legally available therefore, when and as declared by our Board of Directors.
Issuer Sales and Purchases of Equity Securities
There were no sales of equity securities by the Company during the period covered by this report. The following table details the Company’s purchases of shares for the three months ended December 31, 2025.
|
2025 Month |
Total Number of Purchased |
Average Price |
Maximum Number of Shares That May Yet Be Purchased Under The Program at Month-End(1) |
|||||||||
|
October |
6,000 | $ | 142.51 | 90,044 | ||||||||
|
November |
2,500 | $ | 146.65 | 87,544 | ||||||||
|
December |
1,500 | $ | 176.80 | 86,044 | ||||||||
|
Total/Average |
10,000 | $ | 148.69 | |||||||||
|
(1) |
In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, June 13, 2018 and June 7, 2023, the Board of Directors of the Company approved an additional 500,000, 200,000 and 300,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 4,000,000 shares have been authorized to date under this program. Through December 31, 2025, a total of 3,913,956 shares have been repurchased under this program for $116,968,950 at an average price of $29.89 per share. |
PART II—OTHER INFORMATION
|
Item 6. |
RESERVED |
|
Item 7. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.
Overview:
We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, and Oklahoma. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.
We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.
Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.
Market Conditions and Commodity Prices:
Our financial results depend on many factors, particularly the price of natural gas and crude oil 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, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. Index prices for oil, natural gas, and NGLs have been volatile in recent years and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues.
Critical Accounting Estimates:
Proved Oil and Gas Reserves
Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very 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.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Asset Retirement Obligation (ARO):
The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value
Liquidity and Capital Resources:
Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage, and available capacity under our revolving credit facility.
Net cash provided by operating activities for the year ended December 31, 2025, was $96.7 million compared to $115.9 million in the prior year.
Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.
If our exploratory drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2026, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2026 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures.
The Company maintains a Credit Agreement with a maturity date of December 20, 2028, providing for a credit facility totaling $300 million, with a borrowing base of $115 million. As of April 15, 2026, the Company had no outstanding borrowings and $115 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at its discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for June 2026. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.
Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than 15%, then the borrower shall not be required to enter into any swap agreements. As of the quarter ended December 31, 2025, the Company had zero in outstanding borrowings and $115 million in availability. Accordingly, the Company had no swap agreements in place for oil and natural gas.
Development and Other Activities
The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower-risk wells with a high probability of success and higher-risk wells with greater economic potential. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.
In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County. In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing
$37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our “Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000. Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,800. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals.
In addition to this activity, in June of 2024, we participated with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract. Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and in total invested approximately $36.3 million. In addition, in November of 2024, in Reagan County, we participated with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total invested roughly $23 million through completion of production facilities. These 15 horizontals were on production in May 2025. By the end of 2025, therefore, the Company has invested approximately $59.3 million in these additional 21 horizontal wells.
In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; in these, we participated with approximately 3.14% interest and invested $405,000, these wells were completed in May 2025. In the second and third quarters of 2025, we participated in fifteen new horizontals in the Midland Basin of West Texas: these 15 wells are on production as of September 2025 and are operated by Double Eagle on our “Full House” tract in Reagan County in which the Company participated with approximately 27% interest and invested approximately $30.1 million. In addition to the Reagan County activity, the company participated in eight “Horseshoe” wells in Midland County with Vital Energy. Drilling activity with these wells began in the second quarter and the well were put on production during the fourth quarter of 2025. The Company has an average of 8.2% interest in these eight wells and invested approximately $5.4 million. We also participated with Devon Energy Production on two "Evelyn" wells in Kingfisher County, Oklahoma; we participated with approximately 9.95% interest and $1.4 million. These wells were drilled in July 2025 and completed November 2025. In total in these 27 wells, we invested approximately $37.3 million.
In 2026, we have plans to participate with Validus Energy II in the drilling of one 3-mile long horizontal well in Grady County, Oklahoma with 3.47% interest, investing roughly $351,000 through completion, one well with Ovintiv Mid-Continent in the drilling of one 2.5-mile long horizontal in Garvin County, Oklahoma with 3.36% interest, investing roughly $291,000 through completion, and one 3-mile long horizontal in Garvin County, Oklahoma with a 2.27% interest, investing roughly $194,000 through completion.
During 2025, to supplement cash flow and finance our future drilling programs, the Company sold 76 net mineral acres in Glasscock County, Texas. For these mineral acres, we received $950,000 in gross proceeds. A limited partnership, in which the company has interest, sold a retail shopping center located in Prattville, Alabama, distributing $1.2 million to the Company from the proceeds of the sale.
The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.
The Company has a stock repurchase program in place, spending under this program in 2025 and 2024 was $13.6 million and $13.4 million, respectively.
Since 1990, including pursuant to the stock repurchase program authorized by the Board of Directors in December 1993, the Company has repurchased 6,071,995 shares at an average price of $20.16 per share. The Company has also repurchased 769,500 options at an average price of $0.79 per option. Under the current stock repurchase program authorized by the Board of Directors in December 1993, 86,044 shares remain available for repurchase.
Over time, these repurchases have meaningfully reduced the Company’s shares outstanding from approximately 7.6 million shares in 1987 to approximately 1.6 million shares currently. The Company believes that this sustained reduction in share count has contributed significantly to long-term per-share value creation for all shareholders.
As a result of the reduction in shares outstanding over time, the ownership percentage of certain long-term stockholders, including the Chairman and Chief Executive Officer, Charles Drimal, has increased. Mr. Drimal has not materially increased his ownership through open market purchases; rather, his ownership percentage has increased primarily as a result of the decrease in the number of shares outstanding. As of December 31, 2025, Mr. Drimal beneficially owns, including the effect of stock options and voting arrangements, approximately 55.4% of the Company’s fully diluted shares.
The Board of Directors regularly reviews and evaluates the Company’s capital allocation priorities. In doing so, the Board considers a variety of factors, including market conditions, the Company’s financial position, liquidity, and the impact of repurchases on the Company’s stockholder base. The Company expects continued spending under the stock repurchase program in 2026.
Results of Operations
2025 and 2024 Compared
We reported a net income of $26.3 million for 2025, or $15.85 per share, compared to $55.4 million for 2024, or $31.43 per share for 2024.
Oil, NGL and gas sales decreased $45.5 million, or 20.4% to $177.5 million for the year ended December 31, 2025 from $223 million for the year ended December 31, 2024. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head decreased an average of $12.48 per barrel, or 16.5% on crude oil, decreased an average of $4.93 per barrel, or 24.4% on NGL and increased $0.33 per Mcf, or 77.3% on natural gas during 2025 as compared to 2024.
Our crude oil production decreased by 270,000 barrels, or 10.6% to 2,286,000 barrels for the year ended December 31, 2025 from 2,556,000 barrels for the year ended December 31, 2024. Our NGL production increased by 366,000 or 28.5% to 1,650,000 for the year ended December 31, 2025 from 1,284,000 barrels for the year ended December 31, 2024. Our natural gas production increased by 2,059 MMcf, or 26.5% to 9,825 MMcf for the year ended December 31, 2025 from 7,766 MMcf for the year ended December 31, 2024. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.
The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2025 and 2024 (excluding realized gains and losses from derivatives).
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Years ended |
Increase / |
Increase / |
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2025 |
2024 |
(Decrease) |
(Decrease) |
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Barrels of Oil Produced |
2,286,000 | 2,556,000 | (270,000 | ) | (10.6 | )% | ||||||||||
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Average Price Received |
$ | 63.32 | $ | 75.80 | $ | (12.48 | ) | (16.5 | )% | |||||||
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Oil Revenue (In 000’s) |
$ | 144,749 | $ | 193,737 | $ | (48,988 | ) | (25.3 | )% | |||||||
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Mcf of Gas Sold |
9,825,000 | 7,766,000 | 2,059,000 | 26.5 | % | |||||||||||
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Average Price Received |
$ | 0.76 | $ | 0.43 | $ | 0.33 | 77.3 | % | ||||||||
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Gas Revenue (In 000’s) |
$ | 7,490 | $ | 3,309 | $ | 4,181 | 126.4 | % | ||||||||
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Barrels of Natural Gas Liquids Sold |
1,650,000 | 1,284,000 | 366,000 | 28.5 | % | |||||||||||
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Average Price Received |
$ | 15.32 | $ | 20.25 | $ | (4.93 | ) | (24.4 | )% | |||||||
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Natural Gas Liquids Revenue (In 000’s) |
$ | 25,274 | $ | 25,996 | $ | (722 | ) | (2.8 | )% | |||||||
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Total Oil & Gas Revenue (In 000’s) |
$ | 177,513 | $ | 223,042 | $ | (45,529 | ) | (20.4 | )% | |||||||
Oil and gas production expense decreased $2.7 million, or 5.7% to $45.0 million for the year ended December 31, 2025 from $47.7 million for the year ended December 31, 2024. These changes reflect fewer workover related costs in 2025 offset by increases in service rates related to recurring lease operating expenses.
Production and ad valorem taxes decreased $2.1 million, or 17.7% to $10.0 million for the year ended December 31, 2025 from $12.1 million for the year ended December 31, 2024. This decrease reflect the lower oil and natural gas liquid revenues partially offset by higher gas revenues during the year.
Field service income decreased $2.5 million or 25.3% to $8.4 million for the year ended December 31, 2025 from $10.9 million for the year ended December 31, 2024. Workover rig services, hot oil treatments, water hauling and salt water disposal represent the bulk of our field service operations. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.
Field service expense decreased $2.9 million, or 32.0% to $6.2 million for the year ended December 31, 2025 from $9.1 million for the year ended December 31, 2024. Field service expenses primarily consist of wages and vehicle operating expenses. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.
Depreciation, depletion, and amortization decreased $0.8 million, or 1.0% to $75.7 million for the year ended December 31, 2025 from $76.5 million for the year ended December 31, 2024.
General and administrative expense decreased $0.5 million, or 2.7% to $18.4 million for the year ended December 31, 2025 from $18.9 million for the year ended December 31, 2024. This decrease is primarily related lower to employee compensation, benefits and other corporate costs.
Interest and other income of $1.54 million for the ended December 31, 2025 includes distributions from Alabama Shopping Center Associates limited partnership, generated by the partnership's sale of the Prattville, Alabama center.
Interest expense increased $0.7 million, or 44.3% to $2.2 million for the year ended December 31, 2025 from $1.5 million for the year ended December 31, 2024. This increase reflects the higher interest and fee rates combined with borrowings throughout the twelve months of 2025 under our revolving credit agreement.
Tax expense of $4.2 million and $15.8 million were recorded for the years ended December 31, 2025 and 2024, respectively. The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2025.
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Item 7A. |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
We are a smaller reporting company and therefore no response is required pursuant to this Item.
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Item 8. |
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. |
The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1 of this Report.
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Item 9. |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. |
On June 27, 2025, the Audit Committee (the “Committee”) of the Board of Directors of PrimeEnergy Resources Corporation approved the dismissal of Grassi & Co., CPAs, P.C. (“Grassi”) as the Company’s independent registered public accounting firm. On June 27, 2025 (the “Dismissal Date”), the Company notified Grassi of its dismissal effective immediately.
Grassi’s reports on the Company’s consolidated financial statements as of and for the fiscal years ended December 31, 2024 and 2023 did not contain an adverse opinion or a disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles.
During the fiscal years ended December 31, 2024 and 2023 and in the subsequent interim period through the Dismissal Date, there were (i) no disagreements between the Company and Grassi on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreement, if not resolved to the satisfaction of Grassi, would have caused Grassi to make reference to the subject matter of the disagreement in its reports on the consolidated financial statements for such years and (ii) no “reportable events” (as that term is defined in Item 304(a)(1)(v) of Regulation S-K).
(Also, on June 27, 2025 (the “Engagement Date”), the Committee approved the engagement of Withum Smith+Brown, PC (“Withum”) as the Company’s independent registered public accounting firm. Withum was formally engaged on June 27, 2025.
During the Company’s fiscal years ended December 31, 2024 and 2023 and the subsequent interim period through the Engagement Date, neither the Company nor anyone on its behalf has consulted with Withum regarding (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s financial statements, and neither a written report nor oral advice was provided to the Company that Withum concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing, or financial reporting issue or (ii) any matter that was either the subject of a “disagreement” (as that term is defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K) or a “reportable event” (as that term is defined in Item 304(a)(1)(v) of Regulation S-K).
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Item 9A. |
CONTROLS AND PROCEDURES. |
As of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”). Disclosure Controls, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Our management, including the chief executive officer and chief financial officer, does not expect that our Disclosure Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls also is 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 goals under all potential future conditions.
Members of our management, including our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange Act Rules 13a-15 or 15d-15, as of December 31, 2025 the end of the period covered by this Report. Based upon that evaluation, these officers concluded that our disclosure controls and procedures were effective as of December 31, 2025.
Management’s Report on Internal Control Over Financial Reporting
Our management 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. Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with U.S. generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2025. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control – Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
As a result of this assessment, management concluded that, as of December 31, 2025, our internal control over financial reporting was effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
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Item 9B. |
OTHER INFORMATION. |
During the three months ended December 31, 2025,
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Item 9C. |
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. |
Not applicable.
PART III
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Item 10. |
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. |
Information relating to the Company’s Directors, nominees for Directors and executive officers and the Company’s insider trading policy will be included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held on June 10, 2026, and which is incorporated herein by reference.
Code of Conduct and Ethics
We have
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Item 11. |
EXECUTIVE COMPENSATION. |
Information relating to executive compensation will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held on June 10, 2026, and which is
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Item 12. |
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. |
Information relating to security ownership of certain beneficial owners and management will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held on June 10, 2026, and which is incorporated herein by reference.
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Item 13. |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. |
Information relating to certain transactions by Directors and executive officers of the Company will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held on June 10, 2026, and which is incorporated herein by reference.
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Item 14. |
PRINCIPAL ACCOUNTANT FEES AND SERVICES. |
Information relating to principal accountant fees and services will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held on June 10, 2026, and which is incorporated herein by reference.
PART IV
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Item 15. |
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. |
The following documents are filed as part of this Report:
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1. |
Financial statements (Index to Consolidated Financial Statements at page F-1 of this Report) |
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2. |
Financial Statement Schedules - All Financial Statement Schedules have been omitted because the required information is included in the Consolidated Financial Statements or the notes thereto, or because it is not required. |
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3. |
Exhibits: |
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3.1 |
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3.2 |
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4.1 |
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10.18 |
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10.22.6 |
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10.22.6.1 |
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10.22.6.2 |
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10.22.6.3 |
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10.22.6.4 |
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10.22.6.5 |
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19.1 |
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21 |
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23 |
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23.1 |
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31.1 |
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31.2 |
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32.1 |
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32.2 |
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97.1 |
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99.1 |
Summary Reserve Report, dated February 6, 2026, of Ryder Scott Company, L.P. (filed herewith). |
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101.INS |
Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith) |
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101.SCH |
Inline XBRL Taxonomy Extension Schema Document (filed herewith) |
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101.CAL |
Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith) |
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101.DEF |
Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith) |
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101.LAB |
Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith) |
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101.PRE |
Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith) |
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104 |
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
Item 16. FORM 10-K SUMMARY.
None.
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, on the 15th day of April, 2026.
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PrimeEnergy Resources Corporation |
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By: |
/s/ Charles E. Drimal, Jr. |
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Charles E. Drimal, Jr. |
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Chairman, Chief Executive Officer and President |
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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 indicated and on the 15th day of April, 2026.
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/s/ Charles E. Drimal, Jr. |
Chairman, Chief Executive Officer and President; |
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Charles E. Drimal, Jr. |
Principal Executive Officer |
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/s/ Beverly A. Cummings |
Director, Executive Vice President and Treasurer; |
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Beverly A. Cummings |
Principal Financial Officer and Principal Accounting Officer |
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/s/ Clint Hurt |
Director |
/s/ Thomas S. T. Gimbel |
Director |
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Clint Hurt |
Thomas S. T. Gimbel |
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/s/ H. Gifford Fong |
Director |
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H. Gifford Fong |
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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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Reports of Independent Registered Public Accounting Firms |
F-2 |
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Financial Statements |
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Consolidated Balance Sheets – As of December 31, 2025 and 2024 |
F-8 |
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Consolidated Statements of Income – For the years ended December 31, 2025 and 2024 |
F-9 |
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Consolidated Statements of Equity – For the years ended December 31, 2025 and 2024 |
F-10 |
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Consolidated Statements of Cash Flows – For the years ended December 31, 2025 and 2024 |
F-11 |
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Notes to Consolidated Financial Statements |
F-12 |
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Supplementary Information: |
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Capitalized Costs Relating to Oil and Gas Producing Activities, years ended December 31, 2025 and 2024 |
F-23 |
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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities, years ended December 31, 2025 and 2024 |
F-24 |
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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, years ended December 31, 2025 and 2024 |
F-25 |
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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves, years ended December 31, 2005 and 2024 |
F-25 |
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Reserve Quantity Information, years ended December 31, 2025 and 2024 |
F-25 |
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Results of Operations from Oil and Gas Producing Activities, years ended December 31, 2025 and 2024 |
F-25 |
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Notes to Supplementary Information |
F-25 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
PrimeEnergy Resources Corporation and Subsidiaries
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheet of PrimeEnergy Resources Corporation and subsidiaries (the “Company”) as of December 31, 2025, and the related consolidated statements of income, equity and cash flows for the year ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and the results of its operations and its cash flows for the year ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis of Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 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 audit, 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 entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Depletion, Depreciation, and Amortization (“DD&A”) and Impairment Calculation
Critical Audit Matter Description
At December 31, 2025, the carrying value of the Company’s oil and gas properties was $293.8 million, and depreciation, depletion and amortization (“DD&A”) expense was $75.7 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, capitalized costs of proved properties are depleted using the units of production method based on total proved, and proved producing reserves, as estimated by independent petroleum engineers. The Company’s proved oil and natural gas properties are evaluated for impairment utilizing the Company’s proved oil and natural gas reserves in accordance with accounting principles generally accepted in the United States of America.
The Company engages an independent petroleum reservoir engineering firm and an independent petroleum engineer to serve as a management specialist and to assist with the estimation of proved oil and natural gas reserves. To estimate the volume of proved oil and natural gas reserves and associated future net cash flows, management and their specialists make significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties (“PUDs”). Proved reserve estimates are impacted by various inputs, including historical production, oil and gas price assumptions, and future operating and capital cost assumptions, among other factors. Proved oil and natural gas reserves are impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required. Changes in significant assumptions or engineering data could have a significant impact on the amount of DD&A and impairment recorded for the Company’s proved oil and natural gas properties. Because of the complexity involved in estimating oil and gas reserves, the Company utilized independent petroleum engineers for the year ended December 31, 2025.
We identified the impact of proved oil and natural gas reserves on DD&A and the impairment assessment as a critical audit matter due to use of significant judgment by management, including the use of independent petroleum engineers as specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, determination of the inputs described above used by the petroleum engineers in estimating proved oil and gas reserves, subjectivity, and effort in performing procedures and evaluating audit evidence related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to the evaluation of DD&A of oil and gas properties included the following, among others:
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We obtained an understanding and evaluated the design of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data utilized by the engineers in estimating oil and gas reserves. |
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We evaluated the professional qualifications and objectivity of the Company’s independent petroleum reservoir engineering firm and engineers and their relationship to the Company who are responsible for the preparation of the proved oil and gas reserve estimates. |
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We engaged an independent third-party petroleum engineering specialist to perform a technical review of the Company’s reserves report audited by Company’s independent petroleum engineers with an effective date of 01/01/2026. |
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We read the reserve study and evaluated the methodologies and assumptions utilized by the Company’s independent engineers to ensure they were reasonable and in accordance with industry standards. |
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We compared the Company’s recent production with its reserve estimates for properties that have significant production or significant reserve quantities and inquired of disproportionate ratios that did not align with our expectations. Performing analytical procedures on pricing, reserve quantities and cost estimates developed by management and its specialists. Those procedures entailed comparisons of: |
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prices to historical benchmark prices, adjusted for pricing differentials, |
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production forecasts to recent historical actual production, |
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projections of lease operating costs to costs incurred by property during the year ended December 31, 2025, |
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projected production taxes to recent historical taxes incurred and to statutory tax rates, and |
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assessed the reasonableness of forecasted capital expenditures by comparing to recent drilling costs. |
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We performed retrospective review of estimates of proved oil and natural gas reserves to historical estimates to identify potential management bias in estimates. |
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We tested the mathematical accuracy of the DD&A and impairment calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports. |
Other Matter
The consolidated financial statements of the Company, including the accompanying consolidated balance sheet, as of December 31, 2024, and the related consolidated statements of income, changes of equity, and cash flows for the year ended December 31, 2024 and the related notes were audited by Grassi & Co., CPAs, P.C., and rendered their opinion on such statements on April 15, 2025.
/s/
April 15, 2026
PCAOB ID
We have served as the Company's auditor since 2025.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To The Board of Directors and Stockholders of
PrimeEnergy Resources Corporation and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of PrimeEnergy Resources Corporation and Subsidiaries (the “Company”) as of December 31, 2024, the related consolidated statements of income, equity and cash flows for the year then ended, 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 the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
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 audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit 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 audit, 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 audit 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 audit 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 audit provides 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.
Depreciation, Depletion and Amortization of Oil and Gas Properties
Critical Audit Matter Description
At December 31, 2024, the carrying value of the Company’s oil and gas properties was $293.9 million, and depreciation, depletion and amortization (“DD&A”) expense was $76.5 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, capitalized costs of proved properties are depleted using the units of production method based on proved reserves, as estimated by independent petroleum engineers. Proved reserve estimates are impacted by various inputs, including historical production, oil and gas price assumptions, and future operating and capital cost assumptions, among other factors. Because of the complexity involved in estimating oil and gas reserves, the Company utilized independent petroleum engineers for the year ended December 31, 2024.
Auditing the Company’s DD&A calculations is complex because of the use of independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to the evaluation of DD&A of oil and gas properties included the following, among others:
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● |
We obtained an understanding and evaluated the design of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data utilized by the engineers in estimating oil and gas reserves. |
|
● |
We evaluated the professional qualifications and objectivity of the Company’s independent petroleum engineers responsible for the preparation of the proved oil and gas reserve estimates for select properties. |
|
● |
We evaluated the methodologies and assumptions utilized by the Company’s independent engineers to ensure they were reasonable and in accordance with industry standards. |
|
● |
We compared the Company’s recent production with its reserve estimates for properties that have significant production or significant reserve quantities and inquired of disproportionate ratios that did not align with our expectations. |
|
● |
We tested the mathematical accuracy of the DD&A calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports. |
Accounting for Asset Retirement Obligations
Critical Audit Matter Description
At December 31, 2024, the asset retirement obligation (“ARO”) balance totaled $13.9 million. As further described in Note 1, the Company’s ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon, and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.
Auditing the Company’s ARO is complex and highly judgmental because of the significant estimation by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to the evaluation of the accounting for the ARO included the following, among others:
|
● |
We obtained an understanding and evaluated the design of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. Our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. |
|
● |
We compared the ARO against historical results, reviewed the reasonableness of the discount rate utilized in the estimate, considered the reasonableness of the current and long-term portion of the obligation by comparing the accretion expense trends, and considered the completeness of the properties included in the estimate by comparing to the Company’s reserve reports. |
/s/ GRASSI & CO., CPAs, P.C.
We have served as the Company's auditor from 1989 to 2025.
Jericho, New York
April 15, 2025
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except share data)
|
As of December 31, |
||||||||
|
2025 |
2024 |
|||||||
|
ASSETS |
||||||||
|
Current Assets |
||||||||
|
Cash and cash equivalents |
$ | $ | ||||||
|
Accounts receivable, net of an allowance for credit losses of $ |
||||||||
|
Prepaid assets |
||||||||
|
Other current assets |
||||||||
|
Total Current Assets |
||||||||
|
Property and Equipment |
||||||||
|
Oil and gas properties at cost |
||||||||
|
Less: Accumulated depletion and depreciation |
( |
) |
( |
) |
||||
|
Field and office equipment at cost |
||||||||
|
Less: Accumulated depreciation |
( |
) |
( |
) |
||||
|
Total Property and Equipment, Net |
||||||||
|
Other Assets |
||||||||
|
Total Assets |
$ | $ | ||||||
|
LIABILITIES AND EQUITY |
||||||||
|
Current Liabilities |
||||||||
|
Accounts payable |
$ | $ | ||||||
|
Accrued liabilities |
||||||||
|
Due to related parties |
||||||||
|
Current portion of other long-term obligations |
||||||||
|
Asset retirement obligations |
||||||||
|
Long-Term Bank Debt |
||||||||
|
Asset Retirement Obligations, net of current portion |
||||||||
|
Deferred Income Taxes |
||||||||
|
Other Long-Term Obligations |
||||||||
|
Total Liabilities |
||||||||
|
Commitments and Contingencies |
|
|
||||||
|
Equity |
||||||||
|
Common stock, $ par value; 2025 and 2024: Authorized: |
||||||||
|
Paid-in capital |
||||||||
|
Retained earnings |
||||||||
|
Treasury stock, at cost; 2025: |
( |
) |
( |
) |
||||
|
Total Stockholders’ Equity |
||||||||
|
Total Liabilities and Equity |
$ | $ | ||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars, except per share amounts)
|
For the Years Ended |
||||||||
|
2025 |
2024 |
|||||||
|
Revenues and other income: |
||||||||
|
Oil |
$ | $ | ||||||
|
Natural gas |
||||||||
|
Natural gas liquids |
||||||||
|
Field service |
||||||||
|
Interest and other income, net |
||||||||
|
Gain on disposition of assets, net |
||||||||
|
Costs and expenses: |
||||||||
|
Oil and gas production |
||||||||
|
Production and Ad valorem taxes |
||||||||
|
Field service |
||||||||
|
Depreciation, depletion and amortization |
||||||||
|
Accretion of discount on asset retirement obligations |
||||||||
|
General and administrative |
||||||||
|
Interest |
||||||||
|
Income before income tax provision |
||||||||
|
Income tax provision |
||||||||
|
Net income attributable to common stockholders |
$ | $ | ||||||
|
Net Income per share attributable to Common Stockholders: |
||||||||
|
Basic |
$ | $ | ||||||
|
Diluted |
$ | $ | ||||||
|
Weighted average shares Outstanding: |
||||||||
|
Basic |
||||||||
|
Diluted |
||||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Thousands of dollars, except share amounts)
|
Common Stock |
Additional |
|||||||||||||||||||||||
|
Shares |
Common |
Paid-In Capital |
Retained Earnings |
Treasury Stock |
Total Equity |
|||||||||||||||||||
|
Balance at December 31, 2023 |
$ | $ | $ | $ | ( |
) |
$ | |||||||||||||||||
|
Purchase of treasury shares, at cost |
( |
) |
( |
) |
( |
) |
||||||||||||||||||
|
Net income |
- | |||||||||||||||||||||||
|
Balance at December 31, 2024 |
( |
) | ||||||||||||||||||||||
|
Purchase of treasury shares, at cost |
( |
) | ( |
) | ( |
) | ||||||||||||||||||
|
Net income |
- | |||||||||||||||||||||||
|
Balance at December 31, 2025 |
$ | $ | $ | $ | ( |
) |
$ | |||||||||||||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
|
For the Years Ended |
||||||||
|
2025 |
2024 |
|||||||
|
Cash Flows from Operating Activities: |
||||||||
|
Net Income |
$ | $ | ||||||
|
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
|
Depreciation, depletion and amortization |
||||||||
|
Accretion of discount on asset retirement obligations |
||||||||
|
Gain on sale and exchange of assets |
( |
) |
( |
) |
||||
|
Provision for deferred income taxes |
||||||||
|
Allowance for credit losses (recovery) |
( |
) | ||||||
|
Changes in assets and liabilities: |
||||||||
|
Accounts receivable |
( |
) | ||||||
|
Due to related parties |
( |
) | ( |
) | ||||
|
Prepaid assets |
( |
) | ||||||
|
Other current assets |
||||||||
|
Accounts payable |
( |
) | ||||||
|
Accrued liabilities |
( |
) | ( |
) | ||||
|
Other assets |
( |
) | ||||||
|
Other long-term liabilities |
( |
) |
( |
) | ||||
|
Net Cash Provided by Operating Activities |
||||||||
|
Cash Flows from Investing Activities: |
||||||||
|
Property expenditures |
( |
) |
( |
) |
||||
|
Proceeds from sale of properties and equipment |
||||||||
|
Net Cash Used in Investing Activities |
( |
) | ( |
) | ||||
|
Cash Flows from Financing Activities: |
||||||||
|
Purchase of treasury shares |
( |
) |
( |
) |
||||
|
Proceeds from long-term bank debt |
||||||||
|
Repayment of long-term bank debt and other long-term obligations |
( |
) | ( |
) | ||||
|
Net Cash Used in Financing Activities |
( |
) |
( |
) |
||||
|
Net (Decrease) Increase in Cash and Cash Equivalents |
( |
) | ||||||
|
Cash and Cash Equivalents at the Beginning of the Year |
||||||||
|
Cash and Cash Equivalents at the End of the Year |
$ | $ | ||||||
|
Supplemental Disclosures: |
||||||||
|
Income taxes paid during the year |
$ | $ | ||||||
|
Interest paid during the year |
$ | $ | ||||||
|
Non-cash investing Transactions |
||||||||
|
Increase(decrease) in accrued capital expenditures for oil and natural gas properties |
$ | ( |
) | $ | ||||
|
Oil and natural gas property costs attributable to the recognition of asset |
||||||||
|
retirement obligations |
$ | $ | ( |
) | ||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Operations and Significant Accounting Policies
Nature of Operations:
PrimeEnergy Resources Corporation (“PERC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Resources Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, primarily in Oklahoma, and Texas. The Company operates approximately
Consolidation and Presentation
The consolidated financial statements include the accounts of PrimeEnergy Resources Corporation, and its subsidiaries. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.
Segment Reporting:
The Company operates as operating segment and reportable segment which is engaged in the exploration, development, and production of oil, gas, and NGLs in Texas and Oklahoma, from which all of its revenues are derived and expenses incurred. All financial results are reviewed by the Chief Executive Officer (“CEO”), the Company’s Chief Operating Decision Maker (“CODM”), on a consolidated basis to evaluate performance of the Company. The single segment constitutes all the consolidated entity and the accompanying consolidated financial statements and the notes to the accompanying consolidated financial statements are representative of such amounts.
Subsequent Events:
Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure, other than as stated in notes 4 and 5, to these consolidated financial statements.
Use of Estimates:
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.
Cash and cash equivalents:
The Company's cash and cash equivalents include cash on hand and short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased.
Accounts receivable, net:
The Company's net accounts receivable balance is primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers and under various joint operating agreements. The Company records allowances for credit losses based on historical collection experience, current and future economic and market conditions, the length of time that the accounts receivables have been outstanding and the financial condition of its purchasers. The Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty, letters of credit or other credit support.
The Company considers forward-looking information to estimate expected credit losses. The Company establishes allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur. The Company estimates uncollectible amounts for joint interest receivables based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. Allowances for credit losses are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and are recorded in expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.
Oil and gas properties:
The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. Oil and gas leasehold acquisition costs are capitalized when incurred and included as unproved oil and gas properties in the consolidated balance sheets. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company’s exploratory wells include extension wells that extend the limits of a known reservoir. Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities, and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory/extension well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is determined to be noncommercial and is charged to exploration and abandonments expense. As of December 31, 2025 and 2024, the Company had no such suspended well costs.
The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and in-process development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, abandonments expense is recognized. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of its amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
Field and Office Equipment:
Field and office equipment is carried at cost. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from
Leases:
The Company enters into operating leases for its office space in Houston and Midland, Texas. The Company recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company's sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability. See Note 5 for additional information.
Capitalization of Interest:
Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.
Impairment of Long-Lived Assets:
The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.
Fair Value:
The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.
The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
Revenue recognition:
The majority of the Company’s production is operated by third party operators where we elect to market our products under the joint operating agreements. Accordingly, we receive our proportionate share of revenue proceeds for production sold by the operator under the operator’s marketing agreements. The Company recognizes revenue net of any costs incurred by the operator or its purchasers in the related period of production. Revenues are also received net of production taxes which are recorded separately in other production and ad valorem taxes.
The Company recognizes revenue related to production from properties operated by the Company when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Revenues are recorded net to our interest and subject to royalties. Each unit of production typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied therefore the transaction price allocated to a remaining performance obligation is not required. The Company believes that the disaggregation of revenue into these three products as presented in the consolidated financial statements of income appropriately depicts how the nature, amount, timing and uncertainty of revenue and cashflows are affected by economic factors based on its geographic location.
Oil sales. The Company recognizes oil sales revenue when (i) control/custody transfers to the purchaser and (ii) the agreed-upon index price, net of any price differentials, is fixed and determinable. Any costs incurred prior to the transfer of control to the customer, such as gathering and transportation costs, are recognized as oil and gas production costs.
NGL and gas sales. Under the majority of the Company’s gas processing contracts, gas is delivered to a midstream processing entity and the Company recognizes revenue when the products are delivered to the midstream gathering or processing entity at a specified index price, net of downstream gathering and processing fees.
Field service income. The majority of the Company’s services are performed under Master Service Agreements. The Company recognizes revenue when the products and services are provided to the customer.
Asset Retirement Obligation:
The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the consolidated statements of income.
Income Taxes:
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2025 and 2024, the Company had valuation allowance.
The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.
General and Administrative Expenses:
General and administrative expenses represent cost and expenses associated with the operation of the Company.
Earnings Per Common Share:
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect the weighted average number of common shares outstanding adjusted for the weighted average effect of dilutive common stock equivalents using the treasury share method.
Statements of Cash Flows:
For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.
Concentration of Credit Risk:
The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.
Hedging:
The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.
The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statements of income.
Recent Accounting Pronouncements:
In December 2023, the Financial Accounting Standards Board (FASB) issued ASU 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” to expand the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning January 1, 2025, with early adoption permitted. The Company adopted ASU 2023-09 as of January 1, 2025, with retrospective application. The adoption did not have a material impact on the Company’s consolidated financial statements.
In November 2024, the Financial Accounting Standards Board (FASB) issued ASU 2024-03 “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses” requiring disclosure of specified information about certain costs and expenses. ASU 2024-03 is effective for annual periods beginning January 1, 2027, with early adoption permitted. The Company is currently evaluating the potential effect that the updated standard will have on its consolidated financial statement disclosures.
2. Acquisitions and Dispositions
2025 Transactions:
In the third quarter of 2025, the Company sold
2024 Transactions:
In the first quarter of 2024, the Company sold
In the third quarter of 2024, acreage transactions included the acquisition of
3. Additional Balance Sheet Information
Accounts receivable at December 31, 2025 and 2024 consisted of the following:
| December 31, | January 1, | |||||||||||
|
(Thousands of dollars) |
2025 |
2024 |
2024 |
|||||||||
|
Joint interest billings |
$ | $ | $ | |||||||||
|
Trade receivables |
||||||||||||
|
Oil and gas sales |
||||||||||||
|
Taxes |
||||||||||||
|
Other |
||||||||||||
| Allowance for credit losses | (558 | ) | (414 | ) | (674 | ) | ||||||
|
Total |
$ | $ | $ | |||||||||
Accounts payable at December 31, 2025 and 2024 consisted of the following:
|
December 31, |
||||||||
|
(Thousands of dollars) |
2025 |
2024 |
||||||
|
Trade |
$ | $ | ||||||
|
Royalty and other owners |
||||||||
|
Partner advances |
||||||||
|
Other |
||||||||
|
Total |
$ | $ | ||||||
Accrued liabilities at December 31, 2025 and 2024 consisted of the following:
|
December 31, |
||||||||
|
(Thousands of dollars) |
2025 |
2024 |
||||||
|
Compensation and related expenses |
$ | $ | ||||||
|
Property costs |
||||||||
|
Taxes |
||||||||
|
Lease operating costs |
||||||||
|
Other |
||||||||
|
Total |
$ | $ | ||||||
4. Long-Term Debt
Bank Debt:
On July 5, 2022, the Company and its lenders entered into a Fourth Amended and Restated Credit Agreement (the “2022 Credit Agreement”) with a maturity date of June 1, 2026. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $
In 2023 , in lieu of formal amendments, a series of letter agreements authorized by all lenders of the 2022 Credit Agreement and the Company resulted in changes to the amount of the Borrowing Base available throughout the year. The Borrowing Base availability at December 31, 2023 was $
Effective February 9, 2024, the Company and its lenders entered into the Second Amendment to the 2022 Credit Agreement. This amendment included an increase of the Borrowing Base from $
Effective July 29, 2024, the Company and its lenders entered into the Third Amendment to the 2022 Credit Agreement, increasing the Borrowing Base from $
Effective December 20, 2024, the Company and its lenders entered into the Fourth Amendment to the 2022 Credit Agreement, reaffirming the credit agreement at $
The in effect for December 2025, was
Effective February 24, 2026, the Company and its lenders entered into a Fifth Amendment to the 2022 Credit Agreement. All parties agreed to the reaffirmation of the Borrowing base of $
5. Other Long-Term Obligations and Commitments:
Operating Leases:
The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was
On February 10, 2026, the Company entered into a twelve-month lease extension agreement, effective March 1, 2026, with the landlord of the Company’s Houston office. Additional future payments due for this new lease for the years ending December 31, 2026 and 2027 will be $
The payment schedule for the Company’s operating lease obligations as of December 31, 2025 is as follows:
|
(Thousands of dollars) |
Operating |
|||
|
2026 |
$ | |||
|
2027 |
||||
|
2028 |
||||
|
Total undiscounted lease payments |
||||
|
Less: Amount associated with discounting |
( |
) | ||
|
Total net operating lease liabilities |
||||
|
Less: Current portion of |
||||
|
Non-current portion included in |
$ | |||
Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2025 and 2024 is as follows:
|
Years Ended |
||||||||
|
(Thousands of dollars) |
2025 |
2024 |
||||||
|
Asset retirement obligation at beginning of period |
$ | $ | ||||||
|
Net wells placed on production |
||||||||
|
Liabilities settled |
( |
) |
( |
) |
||||
|
Dispositions |
( |
) |
( |
) |
||||
|
Accretion expense |
||||||||
|
Revisions in estimated liabilities |
( |
) | ||||||
|
Asset retirement obligation at end of period |
||||||||
|
Less: Current portion included in Current portion of asset retirement and other long-term obligations |
||||||||
|
Long-term Asset Retirement Obligations |
$ | $ | ||||||
The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.
6. Contingent Liabilities
The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
7. Stock Options and Other Compensation
In May 1989, non-statutory stock options were granted by the Company to key executive officers for the purchase of shares of common stock. At December 31, 2025 and 2024, options on
8. Income Taxes
The components of the provision for income taxes for the years ended December 31, 2025 and 2024 are as follows:
|
Years Ended |
||||||||
|
(Thousands of dollars) |
2025 |
2024 |
||||||
|
Current: |
||||||||
|
Federal |
$ | $ | ||||||
|
State |
||||||||
|
Total current |
||||||||
|
Deferred: |
||||||||
|
Federal |
||||||||
|
State |
||||||||
|
Total deferred |
||||||||
|
Total income tax provision |
$ | $ | ||||||
The components of net deferred tax assets and liabilities are as follows:
|
At December 31, |
||||||||
|
(Thousands of dollars) |
2025 |
2024 |
||||||
|
*Deferred Tax Assets: |
||||||||
|
Accrued liabilities |
$ | $ | ||||||
|
Allowance for credit losses |
||||||||
|
Partnership basis difference |
||||||||
|
State Net operating loss carry-forwards |
||||||||
|
Total deferred tax assets |
||||||||
|
Deferred Tax Liabilities: |
||||||||
|
Depletion and depreciation |
||||||||
|
Total deferred tax liabilities |
||||||||
|
Net deferred tax liabilities |
$ | $ | ||||||
The total provision for income taxes for the years ended December 31, 2025 and 2024 varies from the federal statutory tax rate as a result of the following:
|
December 31, |
December 31, |
|||||||||||||||
|
(Thousands of dollars) |
2025 |
2024 |
||||||||||||||
|
Expected tax expense |
$ | % | $ | % | ||||||||||||
|
Permanent differences |
% | % | ||||||||||||||
|
State income tax, net of federal benefit |
% | % | ||||||||||||||
|
Provision to return adjustment |
( |
) |
( |
) | ( |
( |
)% | |||||||||
|
Tax credits |
( |
) | ( |
)% | ( |
( |
)% | |||||||||
|
Other, Net |
( |
) | ( |
)% | % | |||||||||||
|
Total income tax provision |
$ | % | $ | % | ||||||||||||
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.
The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate. The availability of the percentage depletion deduction is phased out as an entity’s production exceeds certain levels, and based on the Company’s increasing production the percentage depletion deduction is becoming less significant.
The Company is allowed a credit against the Texas Franchise Tax based on net operating losses incurred in prior periods. The credits allowed are $
The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, 2009 and 2017 federal income tax returns have been audited by the Internal Revenue Service. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. Federal and State returns for the years 2022 through 2024 remain open for examination by the relevant taxing authorities.
9. Segment Information and Major Customers
The Company operates in one industry – oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States. The Company sells its oil and natural gas and liquids production to a number of direct purchasers under direct contracts or through other operators under joint operating agreements. Listed below are the purchasers of the Company’s production which represented more than
Net income (loss) before income taxes is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources and assessing performance. This measure allows our management to effectively evaluate our operating performance and compare the results between periods. The CODM is our Chief Executive Officer.
|
2025 |
2024 |
|||||||
|
Oil: |
||||||||
|
DE Central Operating, LLC. |
% | % | ||||||
|
Civitas Resources Inc. |
% | % | ||||||
|
APA Corporation. |
% | % | ||||||
|
Natural gas and liquids: |
||||||||
|
DE Central Operating, LLC. |
% | % | ||||||
|
Civitas Resources Inc. |
% | % | ||||||
|
APA Corporation. |
% | % | ||||||
Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers.
10. Related Party Transactions
Amounts due to or from related parties primarily represent receipts or expenses, related to oil and gas properties, collected or paid by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors. Amounts due to related party were $
11. Salary Deferral Plan
The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions, of which $
12. Earnings per Share
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the consolidated financial statements:
|
Years Ended December 31, |
||||||||||||||||||||||||
|
2025 |
2024 |
|||||||||||||||||||||||
|
Net Income |
Weighted |
Per Share |
Net Income |
Weighted |
Per Share |
|||||||||||||||||||
|
Basic |
$ | $ | $ | $ | ||||||||||||||||||||
|
Effect of dilutive securities: |
||||||||||||||||||||||||
|
Options |
||||||||||||||||||||||||
|
Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
UNAUDITED SUPPLEMENTARY INFORMATION
Net Proved Oil, NGL and Natural Gas Reserves
The reserves engineers for Prime Energy Resources for the years ended December 31, 2025 and 2024, was Ryder Scott Company.
In accordance with SEC regulations, the reserves as of December 31, 2025 and 2024 were estimated using benchmark prices, which reflect adjustments to the benchmark prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. Prime Energy Resources reports reserves in three streams; crude oil, natural gas and NGLs.
The SEC has defined proved reserves as the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
The following tables provide an analysis of the changes in estimated proved reserve quantities of crude oil, natural gas and NGLs for the years ended December 31, 2025 and 2024, all of which are located within the United States (in thousands):
|
Year ended December 31, 2025 |
||||||||||||||||
|
Crude Oil |
Natural Gas |
Liquids |
Total |
|||||||||||||
|
(Bbl) |
(Mcf) |
(Bbl) |
Boe |
|||||||||||||
|
Proved reserves as of December 31, 2024 |
||||||||||||||||
|
Revisions of previous estimates |
( |
) | ||||||||||||||
|
Extensions, discoveries and other additions |
||||||||||||||||
|
Production |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
|
Sales of minerals in place |
― |
― |
― |
― |
||||||||||||
|
Purchase of minerals in place |
― |
― |
― |
― |
||||||||||||
|
Proved reserves as of December 31, 2025 |
||||||||||||||||
|
Proved developed reserves |
||||||||||||||||
|
Beginning of year |
||||||||||||||||
|
End of year |
||||||||||||||||
|
Proved undeveloped reserves |
||||||||||||||||
|
Beginning of year |
||||||||||||||||
|
End of year |
||||||||||||||||
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
UNAUDITED SUPPLEMENTARY INFORMATION
|
Year ended December 31, 2024 |
||||||||||||||||
|
Crude Oil |
Natural Gas |
Liquids |
Total |
|||||||||||||
|
(Bbl) |
(Mcf) |
(Bbl) |
Boe |
|||||||||||||
|
Proved reserves as of December 31, 2023 |
||||||||||||||||
|
Revisions of previous estimates |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
|
Extensions, discoveries and other additions |
||||||||||||||||
|
Production |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
|
Sales of minerals in place |
― |
― |
― |
― |
||||||||||||
|
Purchase of minerals in place |
― |
― |
― |
― |
||||||||||||
|
Proved reserves as of December 31, 2024 |
||||||||||||||||
|
Proved developed reserves |
||||||||||||||||
|
Beginning of year |
||||||||||||||||
|
End of year |
||||||||||||||||
|
Proved undeveloped reserves |
||||||||||||||||
|
Beginning of year |
||||||||||||||||
|
End of year |
||||||||||||||||
For the year ended December 31, 2025, Prime Energy Resources had positive revisions of previous estimates of 1.9 million BOE, primarily attributable to the netted positive gas and NGL volumes that contributed 3.0 million BOE and $36 million of PV 10 value. This was offset by 1.1 million BOE of netted negative oil that removed $18 million of PV 10. Known positive and known negative amounts were not significant.
For the year ended December 31, 2025, extensions, discoveries and other additions resulted primarily from 37 new proved undeveloped locations adding 5.0 million BOE. The remaining volumes added from proved producing wells was 563,401 BOE. The 2025 and 2024 extensions and discoveries reflect the drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques. Future development plans are reflective of the current commodity prices and have been established based on an expectation of available cash flows from operations and availability under our revolving credit facility.
Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2025 and 2024 are based on realized prices, which reflect adjustments to the benchmark prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. All prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. Any effect from the commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses would have been computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the oil and natural gas properties of Prime Energy Resources. The estimated future net cash flows are then discounted at a rate of 10%.
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTARY INFORMATION
(Unaudited)
The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented (in thousands):
|
December 31, |
||||||||
|
2025 |
2024 |
|||||||
|
Future cash inflows |
$ | $ | ||||||
|
Future production costs |
( |
) | ( |
) | ||||
|
Future development and abandonment costs |
( |
) | ( |
) | ||||
|
Future income taxes |
( |
) | ( |
) | ||||
|
Future net cash flows |
||||||||
|
10% annual discount for estimated timing of cash flows |
( |
) | ( |
) | ||||
|
Standardized measure of discounted future net cash flows |
$ | $ | ||||||
It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the proved reserves of Prime Energy Resources. Prime Energy Resources cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented (in thousands):
|
December 31, |
||||||||
|
2025 |
2024 |
|||||||
|
Standardized measure of discounted future net cash flows at January 1 |
$ | $ | ||||||
|
Net change in prices and production costs |
( |
) | ( |
) | ||||
|
Changes in estimated future development and abandonment costs |
( |
) | ||||||
|
Sales of crude oil and natural gas produced, net of production costs |
( |
) | ( |
) | ||||
|
Extensions, discoveries and improved recoveries, less related costs |
||||||||
|
Purchases of minerals in place |
― |
― |
||||||
|
Sales of minerals in place |
― |
( |
) | |||||
|
Revisions of previous quantity estimates |
( |
) | ||||||
|
Development costs incurred during the period |
― |
|||||||
|
Change in income taxes |
||||||||
|
Accretion of discount |
||||||||
|
Change in timing of estimated future production and other |
( |
) | ||||||
|
Net change |
( |
) | ( |
) | ||||
|
Standardized measure of discounted future net cash flows at December 31 |
$ | $ | ||||||
Estimates of economically recoverable oil, NGL and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.
Exhibit 23
|
TBPELS REGISTERED ENGINEERING FIRM F-1580 |
||
|
633 17TH STREET SUITE 1700 |
DENVER, COLORADO 80202 |
TELEPHONE (303) 339-8110 |
CONSENT OF RYDER SCOTT COMPANY, L.P.
We consent to the filing of our summary reserve report dated April 15, 2025 as Exhibit 23 to the PrimeEnergy Corporation annual report on Form 10-K for the year ended December 31, 2025 and to any reference made to us on that form 10-K.
|
Very Truly Yours, |
|
|
/s/ Ryder Scott Company, L.P. |
|
|
Ryder Scott Company, L.P. |
|
| April 15, 2026 |
Denver, Colorado
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We hereby consent to the inclusion in this Form 10-K of our report, dated April 15, 2025, with respect to our audit of the consolidated financial statements of PrimeEnergy Resources Corporation and Subsidiaries as of December 31, 2024 and for the year then ended.
/s/Grassi & Co., CPAs, P.C.
Jericho, New York
April 15, 2026
EXHIBIT 31.1
CERTIFICATIONS
I, Charles E. Drimal, Jr., Chief Executive Officer of PrimeEnergy Resources Corporation, certify that:
|
1. |
I have reviewed this Form 10-K for the year ended December 31, 2025, of PrimeEnergy Resources Corporation; |
|
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
|
3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
|
4. |
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
(a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
|
(b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
|
(c) |
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
|
(d) |
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
|
5. |
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
|
(a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
|
(b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
April 15, 2026
|
/s/ Charles E. Drimal, Jr. |
|
Charles E. Drimal, Jr. |
|
Chief Executive Officer |
|
PrimeEnergy Resources Corporation |
EXHIBIT 31.2
CERTIFICATIONS
I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Resources Corporation, certify that:
|
1. |
I have reviewed this Form 10-K for the year ended December 31, 2025, of PrimeEnergy Resources Corporation; |
|
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
|
3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
|
4. |
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
(a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
|
(b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
|
(c) |
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
|
(d) |
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
|
5. |
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
|
(a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
|
(b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
April 15, 2026
|
/s/ Beverly A. Cummings |
|
Beverly A. Cummings |
|
Chief Financial Officer |
|
PrimeEnergy Resources Corporation |
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-K for the year ended December 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles E. Drimal Jr., Chief Executive Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
|
(1) |
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
|
(2) |
The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
|
/s/ Charles E. Drimal, Jr. |
|
Charles E. Drimal, Jr. Chief Executive Officer |
|
April 15, 2026 |
EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-K for the year ended December 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
|
(1) |
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
|
(2) |
The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
|
/s/ Beverly A. Cummings |
|
Beverly A. Cummings Chief Financial Officer |
|
April 15, 2026 |
EXHIBIT 99.1
PrimeEnergy Resources Corporation
Estimated
Future Reserves and Income
Attributable to Certain
Leasehold and Royalty Interests
SEC Parameters
As of
December 31, 2025
|
/s/ Clark D. Parrott |
|
Clark D. Parrott, P.E. |
|
Colorado License No. 35262 |
|
Vice President |
[SEAL]
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
|
February 6, 2026 |
Ms. Beverly A. Cummings
PrimeEnergy Resources Corporation
9821 Katy Freeway, Suite 1050
Houston, TX 77024
Dear Ms. Cummings:
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of PrimeEnergy Resources Corporation (PrimeEnergy) as of December 31, 2025. The subject properties are located in the states of Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Ohio, Oklahoma, Texas, West Virginia and Wyoming. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 6, 2026 and presented herein, was prepared for public disclosure by PrimeEnergy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon and gas reserves of PrimeEnergy as of December 31, 2025.
The estimated reserves and future net income amounts presented in this report, as of December 31, 2025 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.
| 1100 LOUISIANA, SUITE 4600 | HOUSTON, TEXAS 77002-5294 | TEL (713) 651-9191 |
| SUITE 2800, 350 7TH AVENUE, S.W. | CALGARY, ALBERTA T2P 3N9 | TEL (403) 262-2799 |
PrimeEnergy Resources Corporation
February 6, 2026
Page 2
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
PrimeEnergy Resources Corporation
|
As of December 31, 2025 |
|
Proved |
||||||||||||||||
|
Developed |
Total |
|||||||||||||||
|
Producing |
Non-Producing |
Undeveloped |
Proved |
|||||||||||||
|
Net Reserves |
||||||||||||||||
|
Oil/Condensate – Mbbl |
7,371 | 61 | 2,822 | 10,254 | ||||||||||||
|
Plant Products – Mbbl |
6,941 | 40 | 1,063 | 8,044 | ||||||||||||
|
Gas – MMcf |
52,830 | 956 | 6,756 | 60,542 | ||||||||||||
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Income Data ($M) |
||||||||||||||||
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Future Gross Revenue |
$ | 639,404 | $ | 6,863 | $ | 206,988 | $ | 853,255 | ||||||||
|
Deductions |
254,630 | 2,309 | 149,727 | 406,666 | ||||||||||||
|
Future Net Income (FNI) |
$ | 384,774 | $ | 4,554 | $ | 57,261 | $ | 446,589 | ||||||||
|
Discounted FNI @ 10% |
$ | 265,356 | $ | 3,085 | $ | 20,405 | $ | 288,845 | ||||||||
Values may not sum to total due to rounding.
Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used at the request of PrimeEnergy. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one-line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, workover costs, recompletion costs, development costs and certain abandonment costs net of salvage. “Other” deductions shown on the cash flows are workover costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.
Liquid hydrocarbon reserves account for approximately 90 percent and gas reserves account for the remaining 10 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates, which were also compounded monthly. These results are shown in summary form as follows.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PrimeEnergy Resources Corporation
February 6, 2026
Page 3
|
Discounted Future Net Income ($M) |
||||
|
As of December 31, 2025 |
||||
|
Discount Rate |
Total |
|||
|
Percent |
Proved |
|||
| 5 | $350,518 | |||
| 9 | $299,357 | |||
| 15 | $245,744 | |||
| 20 | $213,783 |
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.
The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the behind pipe status category.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal categories, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At PrimeEnergy’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PrimeEnergy Resources Corporation
February 6, 2026
Page 4
PrimeEnergy’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PrimeEnergy owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PrimeEnergy Resources Corporation
February 6, 2026
Page 5
The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. In general, reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through December 2025 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by PrimeEnergy and were considered sufficient for the purpose thereof. In certain early-life cases, producing reserves were estimated by analogy. This method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate.
The reserves for the properties included herein attributable to the non-producing, behind pipe status category were estimated by the volumetric method. The reserves for the undeveloped status category were estimated by analogy. These analyses utilized pertinent well data furnished to Ryder Scott by PrimeEnergy that were available through December 2025. The data utilized from the analogues as well as the well data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.
To estimate economically producible proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
PrimeEnergy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by PrimeEnergy with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, certain abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by PrimeEnergy. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PrimeEnergy Resources Corporation
February 6, 2026
Page 6
Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PrimeEnergy. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.
Ryder Scott furnished the above-mentioned average benchmark prices in effect on December 31, 2025. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PrimeEnergy and accepted as factual data.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.
|
Geographic Area |
Product |
Price Reference |
Average Benchmark Prices |
Average Realized Prices |
|
North America |
||||
|
United States |
Oil/Condensate |
WTI Cushing |
$65.34/bbl |
$65.23/bbl |
|
NGL |
WTI Cushing |
$65.34/bbl |
$17.98/bbl |
|
|
Gas |
Henry Hub |
$3.387/MMBTU |
$1.47/Mcf |
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PrimeEnergy Resources Corporation
February 6, 2026
Page 7
Costs
Operating costs for the leases and wells in this report were furnished by PrimeEnergy and are based on the operating expense reports of PrimeEnergy and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. “Other” deductions shown on the cash flows are workover costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PrimeEnergy. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs were furnished to us by PrimeEnergy and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.
The estimated net cost of abandonment after salvage was included for properties where certain abandonment costs net of salvage were provided by PrimeEnergy and for which they requested be included in our report. The estimates of the net abandonment costs furnished by PrimeEnergy were accepted without independent verification. We have made no inspections to determine if any additional abandonment, decommissioning, and /or restoration costs may be necessary in addition to the costs provided by PrimeEnergy and included herein.
The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with PrimeEnergy’s plans to develop these reserves as of December 31, 2025. The implementation of PrimeEnergy’s development plans as presented to us and incorporated herein is subject to the approval process adopted by PrimeEnergy’s management. As the result of our inquiries during the course of preparing this report, PrimeEnergy has informed us that the development activities included herein have been subjected to and received the internal approvals required by PrimeEnergy’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PrimeEnergy. PrimeEnergy has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, PrimeEnergy has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2025, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Current costs used by PrimeEnergy were held constant throughout the life of the properties.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PrimeEnergy Resources Corporation
February 6, 2026
Page 8
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.
We are independent petroleum engineers with respect to PrimeEnergy. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PrimeEnergy.
We have provided PrimeEnergy with a digital version of the original signed copy retained in our files. In the event there are any differences between the digital version included in filings made by PrimeEnergy and the original signed copy in our files, the original signed file copy shall control and supersede.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
|
Very truly yours,
RYDER SCOTT COMPANY, L.P. TBPELS Firm Registration No. F-1580
/s/ Clark D. Parrott [SEAL]
Clark D. Parrott, P.E. Colorado License No. 35262 Vice President |
CDP (DRO)/pl
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Clark D. Parrott was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein.
Mr. Parrott, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2013 is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies throughout North America. Before joining Ryder Scott, Mr. Parrott served in a number of engineering positions with operators in the Rocky Mountain and Mid Continent regions. For more information regarding Mr. Parrott’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
Mr. Parrott earned a Bachelor of Science degree in Petroleum Engineering from Colorado School of Mines in 1987 and is a registered Professional Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers.
Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Parrott has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal categories, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 2
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, 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 and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): 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).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 3
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 4
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are 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.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
|
(1) |
completion intervals that are open at the time of the estimate but which have not yet started producing; |
|
(2) |
wells which were shut-in for market conditions or pipeline connections; or |
|
(3) |
wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category 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.
|
(i) |
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS