PNRG 10-Q
Primeenergy Resources Corp (PNRG)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended
Or
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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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(State or other jurisdiction of incorporation or organization) |
(I.R.S. employer Identification No.) |
(Address of principal executive offices)
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(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class |
Trading Symbol(s) |
Name of each exchange on which registered |
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
The number of shares outstanding of each class of the Registrant’s Common Stock as of August 14, 2026 was: Common Stock, $0.10 par value
PrimeEnergy Resources Corporation
Index to Form 10-Q
June 30, 2026
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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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Part I—Financial Information |
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Item 1. Financial Statements |
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Condensed Consolidated Balance Sheets – June 30, 2026 (unaudited) and December 31, 2025 |
1 |
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Condensed Consolidated Statements of Income – For the three and six months ended June 30, 2026 and 2025 (unaudited) |
2 |
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Condensed Consolidated Statements of Equity – For the three and six months ended June 30, 2026 and 2025 (unaudited) |
3 |
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Condensed Consolidated Statements of Cash Flows – For the six months ended June 30, 2026 and 2025 (unaudited) |
4 |
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Notes to Consolidated Financial Statements – June 30, 2026 (unaudited) |
5-10 |
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Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation |
11-18 |
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Item 3. Quantitative and Qualitative Disclosures About Market Risk |
19 |
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Item 4. Controls and Procedures |
19 |
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Part II - Other Information |
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Item 1. Legal Proceedings |
20 |
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Item 1A. Risk Factors |
20 |
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |
20 |
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Item 3. Defaults Upon Senior Securities |
20 |
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Item 4. Reserved |
20 |
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Item 5. Other Information |
20 |
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Item 6. Exhibits |
20 |
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Signatures |
21 |
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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(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. |
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(ii) |
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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(iii) |
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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(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 (B) The project has been approved for development by all necessary parties and entities, including governmental entities. |
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(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 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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(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. |
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(ii) |
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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(iii) |
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 Quarterly Report on Form 10-Q (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 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 ESG 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. 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.
PART I—FINANCIAL INFORMATION
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Item 1. |
FINANCIAL STATEMENTS |
PRIMEENERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except share data)
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June 30, |
December 31, |
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(Unaudited) |
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ASSETS |
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Current Assets |
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Cash and cash equivalents |
$ | $ | ||||||
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Accounts receivable, net of an allowance for credit losses of $ |
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Prepaid obligations |
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Derivative assets |
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Other current assets |
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Total Current Assets |
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Property and Equipment |
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Oil and gas properties, at cost |
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Less: Accumulated depletion and depreciation |
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Field and office equipment, at cost |
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Less: Accumulated depreciation |
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( |
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Total Property and Equipment, Net |
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Other Assets |
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Total Assets |
$ | $ | ||||||
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LIABILITIES AND EQUITY |
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Current Liabilities |
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Accounts payable |
$ | $ | ||||||
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Accrued liabilities |
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Due to related parties |
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Current portion of other long-term obligations |
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Asset retirement obligations |
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Total Current Liabilities |
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Long-term bank debt |
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Asset retirement obligations, net of current portion |
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Deferred income taxes |
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Other long-term obligations, net of current portion |
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Total Liabilities |
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Commitments and contingencies |
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Equity |
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Common stock, $ par value; 2026 and 2025: Authorized and issued: |
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Paid-in capital |
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Retained earnings |
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Treasury stock, at cost; 2026: |
( |
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( |
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Total Equity |
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Total Liabilities and Equity |
$ | $ | ||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME – Unaudited
(Thousands of dollars, except per share amounts)
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Three Months Ended |
Six Months Ended |
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2026 |
2025 |
2026 |
2025 |
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Revenues: |
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Oil |
$ | $ | $ | $ | ||||||||||||
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Natural gas |
( |
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Natural gas liquids |
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Field service income |
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Interest and other income, net |
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Gain (loss) on derivative instrument, net |
( |
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Gain on disposition of assets, net |
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Total revenues |
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Costs and expenses: |
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Oil and gas production |
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Production and ad valorem taxes |
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Field service |
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Depreciation, depletion and amortization |
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Accretion of discount on asset retirement obligations |
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General and administrative expense |
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Interest |
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Total costs and expenses |
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Income before taxes |
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Income tax provision |
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Net income |
$ | $ | $ | $ | ||||||||||||
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Net income per share attributable to common stockholders: |
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Basic |
$ | $ | $ | $ | ||||||||||||
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Diluted |
$ | $ | $ | $ | ||||||||||||
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Weighted average shares outstanding: |
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Basic |
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Diluted |
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The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY – Unaudited
Three and Six Months Ended June 30, 2026 and 2025
(Thousands of dollars, except share amounts)
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Common Stock |
Additional |
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Shares |
Common |
Paid-In |
Retained |
Treasury |
Total |
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Balance at December 31, 2024 |
$ | $ | $ | $ | ( |
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Purchase of treasury stock, at cost |
( |
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( |
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( |
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Net Income |
— | |||||||||||||||||||||||
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Balance at March 31, 2025 |
( |
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Purchase of treasury shares, at cost |
( |
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Net income |
— | |||||||||||||||||||||||
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Balance at June 30, 2025 |
$ | $ | $ | $ | ( |
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$ | |||||||||||||||||
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Common Stock |
Additional |
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Shares |
Common |
Paid-In |
Retained |
Treasury |
Total |
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Balance at December 31, 2025 |
$ | $ | $ | $ | ( |
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Purchase of treasury shares, at cost |
( |
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Net income |
— | |||||||||||||||||||||||
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Balance at March 31, 2026 |
( |
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Purchase of treasury shares, at cost |
( |
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Net income |
— | |||||||||||||||||||||||
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Balance at June 30, 2026 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited
(Thousands of dollars)
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Six Months Ended June 30, |
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2026 |
2025 |
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Cash Flows from Operating Activities: |
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Net Income |
$ | $ | ||||||
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Adjustments to reconcile net income to net cash provided by operating activities: |
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Depreciation, depletion and amortization |
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Accretion of discount on asset retirement obligations |
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Gain on sale and exchange of assets |
( |
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( |
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Unrealized gain derivative instruments, net |
( |
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Provision for deferred income taxes |
( |
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Changes in assets and liabilities: |
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Accounts receivable |
( |
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| Prepaid assets | ( |
) | ( |
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Other current assets |
( |
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Other assets |
( |
) | - | |||||
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Accounts payable |
( |
) | ( |
) | ||||
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Accrued liabilities |
( |
) | ( |
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Due to related parties |
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Other liabilities |
- | |||||||
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Net Cash Provided by Operating Activities |
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Cash Flows from Investing Activities: |
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Property expenditures |
( |
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( |
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Proceeds from disposition of properties and equipment |
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Net Cash Used in Investing Activities |
( |
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Cash Flows from Financing Activities: |
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Purchase of stock for treasury |
( |
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( |
) |
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Proceeds from long-term bank debt |
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Repayment of long-term bank debt |
( |
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Net Cash Used in Financing Activities |
( |
) |
( |
) |
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Net increase (decrease) in Cash and Cash Equivalents |
( |
) | ||||||
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Cash and Cash Equivalents at the Beginning of the Period |
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Cash and Cash Equivalents at the End of the Period |
$ | $ | ||||||
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Supplemental Disclosures: |
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Income taxes paid during the year |
$ | $ | ||||||
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Interest paid during the year |
$ | $ | ||||||
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Non-cash financing and investing activities: |
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Change in accrued property costs |
$ | ( |
) | $ | ||||
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Asset retirement obligations |
$ | $ | ||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2026
(1) Basis of Presentation
The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form 10-K for the year ended December 31, 2025. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s consolidated balance sheets as of June 30, 2026, and December 31, 2025, the consolidated results of operations, and equity for the three and six months ended June 30, 2026, and 2025 and the consolidated cashflows for the six months ended June 30, 2026 and 2025.
As of June 30, 2026, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.
(2) Acquisitions and Dispositions
In the first quarter of 2025, the Company recognized a gain of $
In the first quarter of 2026, the Company had no significant acquisitions or dispositions.
In the second quarter of 2026, the Company sold
(3) Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
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(Thousands of dollars) |
June 30, |
December 31, |
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Accounts Receivable: |
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Joint interest billing |
$ | $ | ||||||
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Trade receivables |
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Oil and gas sales |
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Other |
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Less: Allowance for credit losses |
( |
) | ( |
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Total |
$ | $ | ||||||
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Accounts Payable: |
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Trade |
$ | $ | ||||||
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Royalty and other owners |
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Partner advances |
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Other |
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Total |
$ | $ | ||||||
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Accrued Liabilities: |
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Compensation and related expenses |
$ | $ | ||||||
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Property costs |
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Taxes |
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Lease operating costs |
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Other |
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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. The maturity date has been extended again to December 2028. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $
Through a series of amendments since origination the borrowing base determination was adjusted to be $
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 $
Effective August 3, 2026, the Company and its lenders entered into a Borrowing Base Agreement. All parties agreed to a borrowing base of $
The in effect through June 30, 2026, remained at
(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.
The payment schedule for the Company’s operating lease obligations as of June 30, 2026 is as follows:
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(Thousands of dollars) |
Operating |
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2026 (remaining) |
$ | |||
|
2027 |
||||
|
2028 |
||||
|
Total undiscounted lease payments |
||||
|
Less: Amount associated with discounting |
( |
) | ||
|
Total net operating lease liabilities |
||||
|
Less: Current portion of other long-term obligations |
( |
) | ||
|
Non-current portion included in other long-term obligations |
$ | |||
Asset Retirement Obligation
A reconciliation of the liability for plugging and abandonment costs for the six months ended June 30, 2026 is as follows:
|
(Thousands of dollars) |
June 30, |
|||
|
Asset retirement obligations at December 31, 2025 |
$ | |||
|
Dispositions |
( |
) | ||
|
Liabilities settled |
( |
) | ||
|
Accretion of discount |
||||
|
Asset retirement obligations at June 30, 2026 |
||||
|
Less current portion of asset retirement obligations |
||||
|
Asset retirement obligations, long-term |
$ | |||
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 June 30, 2026 and 2025, remaining options held by two key executive officers on
(8) 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 parties were $
(9) Fair Value Disclosures
Fair value is defined 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 Company separates the fair value of its financial instruments using a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants 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 classifies fair value balances based on the observability of those inputs.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placements within the fair value hierarchy levels. There were no derivative contracts at December 31, 2025. The following table provides fair value measurement information for the commodity derivatives measured at fair value on a recurring basis as of June 30, 2026 (in thousands):
|
June 30, 2026 |
||||||||||||||||
|
Level 1 |
Level 2 |
Level 3 |
Total |
|||||||||||||
|
Assets |
||||||||||||||||
|
Assets from derivative contracts |
$ | $ | $ | $ | ||||||||||||
|
Liabilities |
||||||||||||||||
|
Liabilities from derivative contracts |
$ | $ | $ | $ | ||||||||||||
Derivative contracts classified as Level 2 include fixed-price swaps that are recorded at fair value. The Level 2 observable data include, but are not limited to, the contractual price of the underlying position, current market prices, and crude oil forward curves. There were no transfers between fair value hierarchy levels for any period presented. See Note 10, “Derivative Instruments,” for additional discussion of derivatives.
The Company’s derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.
(10) Derivative Instruments
The Company is exposed to commodity price risks relating to its ongoing business operations. From time to time, the Company will manage commodity price risks by entering into certain derivative financial instruments. Derivative instruments are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of income for the period in which the change occurs. With respect to the Company’s derivative assets and liabilities measured at fair value, refer to Note 9, “Fair Value Disclosures,” for discussion of their classification within the fair value hierarchy. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on Derivative instruments, net” on the unaudited condensed consolidated statements of income.
As of June 30, 2026, the Company’s derivative financial instruments consisted of fixed price swaps indexed to West Texas Intermediate (“WTI”) crude oil, whereby the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. The derivative agreements do not contain credit-risk-related contingent features. There are no amounts of related financial collateral received or pledged. The Company does not use any of its derivative instruments for speculative or trading purposes.
The following table summarizes the location and fair value amounts of all commodity derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2026, and December 31, 2025 (in thousands):
|
Balance sheet location |
June 30, 2026 |
December 31, 2025 |
||||||
|
Current assets |
$ | $ | ||||||
|
Noncurrent assets |
||||||||
|
Total assets |
$ | $ | ||||||
|
Current liabilities |
$ | $ | ||||||
|
Noncurrent liabilities |
||||||||
|
Total liabilities |
$ | $ | ||||||
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of income (in thousands):
|
Location of gain (loss) on derivative |
Three Months Ended June 30, |
|||||||||
|
Type |
contracts on Statement of Income |
2026 |
2025 |
|||||||
|
Commodity contracts: |
||||||||||
| Oil derivatives - Unrealized gain (loss) |
Gain (loss) on derivative instrument, net |
$ | $ | |||||||
|
Oil derivatives - Realized gain (loss) |
Gain (loss) on derivative instrument, net |
( |
) | $ | ||||||
|
Total net gain (loss) |
$ | $ | ||||||||
|
Location of gain (loss) on derivative |
Six Months Ended June 30, |
|||||||||
|
Type |
contracts on Statement of Income |
2026 |
2025 |
|||||||
|
Commodity contracts: |
||||||||||
|
Oil derivatives - Unrealized gain (loss) |
Gain (loss) on derivative instruments, net | $ | $ | |||||||
|
Oil derivatives - Realized gain (loss) |
Gain (loss) on derivative instruments, net |
( |
) | $ | ||||||
|
Total net gain (loss) |
$ | ( |
) | $ | ||||||
As of June 30, 2026, the Company had the following open crude oil derivative contracts:
|
2026 |
||||
|
NYMEX WTI Crude Swaps: |
||||
|
Total volumes (Bbls) |
||||
|
Weighted average price |
$ | |||
As of June 30, 2026, the Company is party to derivative contracts with one counterparty. The Company believes the counterparty is of acceptable credit risk, and the creditworthiness of the counterparty is subject to periodic review. The assets and liabilities are netted given that all positions are held by a single counterparty and subject to a master netting arrangement. The combined fair value of derivatives included in the unaudited condensed consolidated balance sheets as of June 30, 2026, and December 31, 2025, is summarized below (in thousands):
|
Assets from Derivative Contracts |
Liabilities from Derivative
Contracts |
|||||||||||||||
|
Offsetting of Derivative Assets and Liabilities |
June 30, 2026 |
December 31, 2025 |
June 30, 2026 |
December 31, 2025 |
||||||||||||
|
Gross amounts of recognized assets and liabilities |
$ | $ | $ | $ | ||||||||||||
|
Gross amounts offset in the balance sheet |
||||||||||||||||
|
Net amounts of assets and liabilities presented in the balance sheet |
$ | $ | $ | $ | ||||||||||||
(11) 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 financial statements:
|
Six Months Ended June 30, |
||||||||||||||||||||||||
|
2026 |
2025 |
|||||||||||||||||||||||
|
Net |
Weighted |
Per |
Net |
Weighted |
Per |
|||||||||||||||||||
|
Basic |
$ | $ | $ | $ | ||||||||||||||||||||
|
Effect of dilutive securities: |
||||||||||||||||||||||||
|
Options |
— | 763,209 | ||||||||||||||||||||||
|
Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
|
Three Months Ended June 30, |
||||||||||||||||||||||||
|
2026 |
2025 |
|||||||||||||||||||||||
|
Net |
Weighted |
Per |
Net |
Weighted |
Per |
|||||||||||||||||||
|
Basic |
$ | $ | $ | $ | ||||||||||||||||||||
|
Effect of dilutive securities: |
||||||||||||||||||||||||
|
Options |
— | 762,807 | ||||||||||||||||||||||
|
Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
|
Item 2. |
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 Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.
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. 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 also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun. In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators. In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that we believe may have future value for producers in the area. We believe our balanced portfolio of assets positions 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 operations, our credit facility, and existing cash on our balance sheet.
In addition to developing our oil and natural gas reserves, we continue to actively pursue the acquisition of producing properties. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition and for exploration and development in areas in which we operate. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income-producing assets or developable leasehold acreage to build stockholder value.
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. 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. 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 may be volatile and, consequently, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.
On occasion, we will use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of 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. When used our derivative contracts are accounted for under mark-to-market accounting and we can expect volatility in gains and losses on contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.
The Company is actively developing additional reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas, the Company maintains an acreage position of approximately 16,998 gross (9,567 net) acres, 97.6% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is 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.
Future development plans are established based on various factors, including the expectation of available cash flows from operations and the availability of funds under our revolving credit facility.
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:
|
Reserve Category |
||||||||||||||||||||||||||||||||||||||||||||||||
|
Proved Developed |
Proved Undeveloped |
Total |
||||||||||||||||||||||||||||||||||||||||||||||
|
As of December 31, |
Oil |
NGLs |
Gas |
Total |
Oil |
NGLs |
Gas |
Total |
Oil |
NGLs |
Gas |
Total |
||||||||||||||||||||||||||||||||||||
|
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 | ||||||||||||||||||||||||||||||||||||
|
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 | ||||||||||||||||||||||||||||||||||||
|
(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 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 in early 2025 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 invested $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 during 2025.
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.
During 2026, we participated with Validus Energy II in the drilling of one three-mile long horizontal well in Grady County, Oklahoma with 2.9% interest, investing roughly $351,000 through completion. This well was put on production during the first quarter of this year. Additional activity during 2026 in West Texas includes continued development in Martin and Upton County. Martin County development includes investing approximately $120,000 across 12 wells to be drilled by Oxyrock in Jo Mill and Middle Spraberry formations as well as the Barnett formation. Development in Upton County will be with Apache at an average of 41.8% ownership across 12 wells in Jo Mill, Lower Spraberry and Wolfcamp A formations. The estimated company investment for these wells and production facility is $34.1 million. During the second quarter of this year, drilling activity started with each of the developments in Martin and Upton County. First production for all 24 wells is estimated in the fourth quarter of this year.
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 |
Future Net |
Present Future |
Future Net |
Present Future |
Present Future |
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 from 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 and Recent Activity
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 June 30, 2026, 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 550 Mcfd and 23 Bopd.
In February of 2026 the Gulf Coast region performed a successful recompletion on the Wing #80 well in the Segno field of Polk County, Texas, at an expense of approximately $167,000, adding roughly 45 BOEPD to the Company’s production. We have plans to recomplete the Wing #85 well in the Segno field of Polk County, Texas, at an expense of approximately $150,000. Other than the previously mentioned recompletion, 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 June 30, 2026, 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 were spud in early March 2025 and completed in May 2025. Our share of these wells is approximately 3.14% and the total investment was 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. During 2026, we have participated with Validus Energy II in the drilling of one 3-mile long horizontal well in Grady County, Oklahoma with 2.9% interest, investing roughly $295,000 through completion. This well was put on production during the first quarter of this year.
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 June 30, 2026, 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 16,998 gross (9,567 net)A 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.
Activity during 2025 included participating 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
Activity for 2026 includes continued development in Martin and Upton County. Martin County development includes investing approximately $120,000 across 12 wells to be drilled by Oxyrock in Jo Mill and Middle Spraberry formations as well as the Barnett formation. Development in Upton County will be with Apache at an average of 41.8% ownership across 12 wells in Jo Mill, Lower Spraberry and Wolfcamp A formations. The estimated company investment for these wells and production facility is $34.1 million. During the second quarter of this year, drilling activity started with each of the developments in Martin and Upton County. First production for all 24 wells is estimated in the fourth quarter of this year.
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 proposals could be put forward within the next two years for the drilling of between 36 and 45 new horizontals that will target the Wolfcamp “D” pay zone in Reagan County, if the current drilling of offset wells is successful. Potentially an additional test well or two may be drilled in one or more of the other undeveloped pay horizons which now will include the Barnett due to upcoming activity in Martin County. 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 2026-2028 timeframe, we have the potential to invest approximately $187 million in horizontal drilling in West Texas over the next several years.
RESULTS OF OPERATIONS
We reported net income of $10.9 million, or $6.72 basic earnings per share, and $6.5 million, or $4.06 basic earnings per share for the six and three months ended June 30, 2026, respectively, as compared to $12.4 million, or $7.37 basic earnings per share, and $3.2 million, or $1.94 basic earnings per share for the six and three months ended June 30, 2025, respectively. Current-year net income reflects lower oil and natural gas liquids production, partially offset by higher realized prices, as well as higher natural gas production, which was adversely affected by negative realized natural gas prices.
Oil, gas and NGLs sales decreased $1.6 million, or 3.9% to $38.3 million for the three months ended June 30, 2026, from $39.8 million for the three months ended June 30, 2025, and decreased $9.3 million, or 10.6% to $77.8 million for the six months ended June 30, 2026, from $87.1 million for the six months ended June 30, 2025. Sales vary due to changes in volumes of production sold and realized commodity prices. Natural gas prices in the Permian Basin were negatively affected by regional pipeline takeaway constraints and limited to transportation capacity, resulting in negative or significantly reduced realized prices for certain Permian natural gas production during the quarter and potentially continuing during the remainder of 2026.
The following tables summarize the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2026 and 2025 (excluding realized gains and losses from derivatives).
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Six months ended June 30, |
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2026 |
2025 |
Increase / |
Increase / |
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Barrels of Oil Sold |
905,000 | 1,057,000 | (152,000 | ) | (14.38 | )% | ||||||||||
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Mcf of Gas Sold |
5,177,000 | 4,815,000 | 362,000 | 7.52 | % | |||||||||||
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Barrels of Natural Gas Liquids Sold |
785,000 | 835,000 | (50,000 | ) | (5.99 | )% | ||||||||||
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Average Price Received Oil |
$ | 83.98 | $ | 63.24 | $ | 20.74 | 32.80 | % | ||||||||
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Average Price Received Gas |
$ | (1.98 | ) | $ | 1.26 | $ | (3.24 | ) | (257.14 | )% | ||||||
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Average Price Received NGL |
$ | 15.34 | $ | 16.94 | $ | (1.60 | ) | (9.45 | )% | |||||||
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Oil Revenue (in 000’s) |
$ | 76,000 | $ | 66,844 | $ | 9,156 | 13.70 | % | ||||||||
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Gas Revenue (in 000’s) |
(10,238 | ) | 6,072 | (16,310 | ) | (268.61 | )% | |||||||||
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Natural Gas Liquids Revenue (in 000’s) |
12,043 | 14,146 | (2,103 | ) | (14.87 | )% | ||||||||||
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Total Oil & Gas Revenue (In 000’s) |
$ | 77,805 | $ | 87,062 | $ | (9,257 | ) | (10.63 | )% | |||||||
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Three months ended June 30, |
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2026 |
2025 |
Increase / |
Increase / |
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Barrels of Oil Sold |
411,000 | 600,000 | (189,000 | ) | (31.50 | )% | ||||||||||
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Mcf of Gas Sold |
2,611,000 | 2,424,000 | 187,000 | 7.71 | % | |||||||||||
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Barrels of Natural Gas Liquids Sold |
398,000 | 381,000 | 17,000 | 4.46 | % | |||||||||||
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Average Price Received Oil |
$ | 98.85 | $ | 56.96 | $ | 41.89 | 73.54 | % | ||||||||
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Average Price Received Gas |
$ | (3.53 | ) | $ | 0.02 | $ | (3.55 | ) | (17,750.00 | )% | ||||||
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Average Price Received NGL |
$ | 17.25 | $ | 14.74 | $ | 2.51 | 17.00 | % | ||||||||
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Oil Revenue (in 000’s) |
$ | 40,629 | $ | 34,178 | $ | 6,451 | 18.87 | % | ||||||||
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Gas Revenue (in 000’s) |
(9,216 | ) | 43 | (9,259 | ) | (21,532.56 | )% | |||||||||
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Natural Gas Liquids Revenue (in 000’s) |
6,865 | 5,617 | 1,248 | 22.22 | % | |||||||||||
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Total Oil & Gas Revenue (In 000’s) |
$ | 38,278 | $ | 39,838 | $ | (1,560 | ) | (3.92 | )% | |||||||
Oil and gas production expense decreased $1.0 million, or 10.4% to $9.1 million for the three months ended June 30, 2026, from $10.1 million for the three months ended June 30, 2025, and decreased $0.9 million, or 4.4% to $18.8 million for the six months ended June 30, 2026, from $19.7 million for the six months ended June 30, 2025. These changes reflect costs related to natural production declines and fewer wells that have been placed on production period over period.
Production and ad valorem taxes increased $2.6 million, or 147.9% to $4.4 million for the three months ended June 30, 2026 from $1.8 million for the three months ended June 30, 2025, and increased $2.6 million, or 51.0% to $7.7 million for the six months ended June 30, 2026, from $5.1 million for the six months ended June 30, 2025. These increases reflect the changes in oil, natural gas and natural gas liquids production in the related periods.
Field service income decreased $0.003 million or 0.15% to $1.972 million for the three months ended June 30, 2026, from $1.975 million for the three months ended June 30, 2025, and decreased $0.4 million, or 8.8% to $3.8 million for the six months ended June 30, 2026, from $4.1 million for the six months ended June 30, 2025. Workover rig services and hot oil treatments represent the bulk of our field service operations where we experienced lower activity in 2026 compared to the prior year comparable period.
Field service expense increased $0.2 million or 13.79% to $1.4 million for the three months ended June 30, 2026, from $1.2 million for the three months ended June 30, 2025, and decreased $0.5 million, or 16.4% to $2.6 million for the six months ended June 30, 2026, from $3.1 million for the six months ended June 30, 2025. Field service expenses primarily consist of wages and vehicle operating expenses which varied period over period.
Depreciation, depletion and amortization expense decreased $4.9 million or 23.4% to $15.9 million for the three months ended June 30, 2026, from $20.8 million for the three months ended June 30, 2025, and decreased $8.5 million, or 20.7% to $32.6 million for the six months ended June 30, 2026, from $41.1 million for the six months ended June 30, 2025. This decrease is due to fewer wells being placed in service and therefore, fewer production volumes on a BOE basis period over period.
General and administrative expense increased $0.05 million or 1.6% to $3.0 million for the three months ended June 30, 2026, from $2.9 million for the three months ended June 30, 2025, and decreased $0.02 million, or 0.3% to $5.86 million for the six months ended June 30, 2025, from $5.88 million for the six months ended June 30, 2025. These changes are nominal and reflect consistent business operations.
Interest expense decreased $0.4 million or 61.8% to $0.3 million for the three months ended June 30, 2026, from $0.7 million for the three months ended June 30, 2025, and decreased $0.8 million, or 58.4% to $0.5 million for the six months ended June 30, 2026, from $1.3 million for the six months ended June 30, 2025. This decrease reflects the lower borrowings during the six months of 2026 under our revolving credit agreement compared to the same period in 2025.
Income tax expense for the June 30, 2026, and 2025 quarters varied due to the change in net income.
LIQUIDITY AND CAPITAL RESOURCES
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. For 2026, we will continue our focus on preserving financial flexibility and ample 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’s horizontal development activities in the last two years, along with our projected activity for 2026, can be summarized as follows: in 2024 we invested $113 million in 48 horizontals, in 2025 we invested $96 million in 48 horizontals, and in 2026, we expect to invest $52 million in 28 horizontals as discussed under district information and recent activity. Therefore, in total, since January 2024 and through 2026, the Company will have invested roughly $261 million in horizontal development, primarily in the Midland Basin of West Texas.
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 natural gas prices vary due to world political events, supply and demand for oil, natural gas and natural gas liquids, product storage levels, transportation constraints, weather patterns and other market conditions. We sell the majority of our production at spot market prices. Accordingly, commodity price volatility directly affects our cash flow from operations. During the first half of 2026, oil prices remained favorable and continued to support our oil-weighted development program and operating cash flows. However, oil prices remain volatile and may fluctuate significantly based on geopolitical events, changes in global supply and demand, inventory levels and market expectations regarding future supply disruptions. Natural gas prices in the Permian Basin were negatively affected by regional pipeline takeaway constraints and limited transportation capacity, resulting in negative or significantly reduced realized prices for certain Permian natural gas production during the quarter and potentially continuing during the remainder of 2026. To mitigate commodity price volatility, we sometimes lock in prices for a portion of our production through the use of derivatives. As of June 30, 2026, the Company had open oil derivative contracts for a total of 367,000 barrels at a weighted average price of $74.84 per barrel.
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. If the borrowing base utilization percentage is less than 15% of total available borrowings, the Company is not required to enter into any hedge agreements at this time. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.
The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $105 million. As of August 14, 2026, the Company’s has no outstanding borrowings under this credit facility. The bank reviews the borrowing base semi-annually and, at their 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 redetermination will be completed pursuant to the requirements of the credit agreement. 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.
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.
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Item 3. |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company is a smaller reporting company and no response is required pursuant to this Item.
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Item 4. |
CONTROLS AND PROCEDURES |
As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company’s internal control over financial reporting that occurred during the last quarter of 2026 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II—OTHER INFORMATION
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Item 1. |
LEGAL PROCEEDINGS |
None.
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Item 1A. |
RISK FACTORS |
The Company is a smaller reporting company and no response is required pursuant to this Item.
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Item 2. |
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
There were no sales of equity securities by the Company during the period covered by this report. The following table details the Company’s purchase of shares for the three months ended June 30, 2026.
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2026 Month |
Number of |
Average Price |
Maximum Shares Be Under at (1) |
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April |
— | $ | — | 71,544 | ||||||||
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May |
18,859 | 176.18 | 52,975 | |||||||||
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June |
12,431 | 179.44 | 340,544 | |||||||||
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Total/Average |
31,290 | $ | 177.48 | |||||||||
| (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, June 7, 2023, and June 10, 2026, the Board of Directors of the Company approved an additional 500,000, 200,000, 300,000 and 300,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 4,300,000 shares has been authorized to date under this program. Through June 30, 2026, a total of 3,959,456 shares have been repurchased under this program for $125,092,638 at an average price of $31.59 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital. |
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Item 3. |
DEFAULTS UPON SENIOR SECURITIES |
None
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Item 4. |
RESERVED |
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Item 5. |
OTHER INFORMATION |
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Item 6. |
EXHIBITS |
The following exhibits are filed as a part of this report:
Exhibit
No.
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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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10.22.6.6 |
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19.1 |
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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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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) |
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
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PrimeEnergy Resources Corporation |
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(Registrant) |
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August 14, 2026 |
/s/ Charles E. Drimal, Jr. |
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(Date) |
Charles E. Drimal, Jr. |
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President |
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Principal Executive Officer |
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/s/ Beverly A. Cummings |
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August 14, 2026 |
Beverly A. Cummings |
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Executive Vice President |
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Principal Financial Officer |