Primeenergy Resources Corp 10-Q for FY2025 Q2
Primeenergy Resources Corp (PNRG)
About this 10-Q
Primeenergy Resources Corp filed this 10-Q on August 19, 2025, covering the quarter ended June 30, 2025 (FY2025 Q2).
Headline figures
Quarter ended June 30, 2025, as reported in this filing, compared with the same period a year earlier where the filing states it.
- Revenue
- $41.98M
- down 35.2% from $64.83M a year earlier
- Net income
- $3.23M
- down 83.6% from net income of $19.73M a year earlier
- Diluted EPS
- $1.33
- down 82.9% from $7.77 a year earlier
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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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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large Accelerated Filer |
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Accelerated Filer |
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Smaller Reporting Company |
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Emerging growth company |
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant 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 13, 2025 was: Common Stock, $0.10 par value
PrimeEnergy Resources Corporation
Index to Form 10-Q
June 30, 2025
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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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Consolidated Balance Sheets – June 30, 2025 and December 31, 2024 |
1 |
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Consolidated Statements of Income – For the three and six months ended June 30, 2025 and 2024 |
2 |
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Consolidated Statements of Equity – For the three and six months ended June 30, 2025 and 2024 |
3 |
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Consolidated Statements of Cash Flows – For the six months ended June 30, 2025 and 2024 |
4 |
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Notes to Consolidated Financial Statements – June 30, 2025 |
5-8 |
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Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation |
9-17 |
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Item 3. Quantitative and Qualitative Disclosures About Market Risk |
17 |
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Item 4. Controls and Procedures |
17 |
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Part II - Other Information |
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Item 1. Legal Proceedings |
18 |
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Item 1A. Risk Factors |
18 |
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |
18 |
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Item 3. Defaults Upon Senior Securities |
18 |
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Item 4. Reserved |
18 |
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Item 5. Other Information |
18 |
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Item 6. Exhibits |
19 |
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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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“Borrowing Base” is the maximum amount a company can borrow under a reserve-based lending (RBL) facility, calculated primarily on the value of its proved reserves. |
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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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In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. |
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Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. |
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(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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Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
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Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
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Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. |
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“PV-10” (Present Value at 10%) measures the future net cash flows from proved reserves, discounted at a fixed 10% annual rate to account for the time value of money. |
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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
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except share data)
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June 30, Unaudited |
December 31, |
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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 |
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Prepaid obligations |
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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, depreciation and amortization |
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Field and office equipment at cost |
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Less: Accumulated depreciation |
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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 property cost |
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Accrued liabilities |
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Due to related parties |
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Current portion of asset retirement and other long-term obligations |
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Total Current Liabilities |
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Long-Term Bank Debt |
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Asset Retirement Obligations |
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Deferred Income Taxes |
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Other Long-Term Obligations |
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Total Liabilities and Contingencies |
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Equity |
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Common stock, $ par value; 2025 and 2024: Authorized and Issued |
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Paid-in capital |
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Retained earnings |
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Treasury stock, at cost; 2025: |
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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
CONSOLIDATED STATEMENTS OF INCOME – Unaudited
Three and Six Months Ended June 30, 2025 and 2024
(Thousands of dollars, except per share amounts)
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Three Months Ended |
Six Months Ended |
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2025 |
2024 |
2025 |
2024 |
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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 |
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Gain on disposition of assets |
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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
CONSOLIDATED STATEMENTS OF EQUITY – Unaudited
Three and Six Months Ended June 30, 2025 and 2024
(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 |
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Net Income |
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Balance at March 31, 2025 |
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Purchase of |
( |
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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, 2023 |
$ | $ | $ | $ | ( |
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Purchase of |
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Net income |
— | |||||||||||||||||||||||
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Balance at March 31, 2024 |
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Purchase of |
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Net income |
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Balance at June 30, 2024 |
$ | $ | $ | $ | ( |
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The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited
Six Months Ended June 30, 2025 and 2024
(Thousands of dollars)
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2025 |
2024 |
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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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Provision for deferred income taxes |
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Changes in assets and liabilities: |
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Accounts receivable |
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Prepaids obligations |
( |
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Other current 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 long-term 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 and other long-term obligations |
( |
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Net Cash Used in Financing Activities |
( |
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( |
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Net 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 |
$ | $ | ||||||
| Non-cash financing and investing activities: | ||||||||
| Change in Accrued Property Costs | $ | $ | ||||||
| Asset Retirement Obligations | $ | $ | ||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2025
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(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, 2024. In the opinion of management, the accompanying interim 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, 2025, and December 31, 2024, the consolidated results of operations, cash flows and equity for the six months ended June 30, 2025, and 2024.
As of June 30, 2025, 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, 2024. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.
Recently Issued Accounting Pronouncements
In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 increases the transparency of expense information presented in the statement of operations through disclosures of expanded disaggregation of relevant expense captions including purchases of inventory, employee compensation, depletion, depreciation, and amortization. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027 with early adoption permitted. The Company is currently evaluating ASU 2024-03 and the impact it may have to the Company’s disclosures.
In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 enhances the transparency of income tax disclosures by expanding the income tax rate reconciliation disclosure and income taxes paid information. ASU 2023-09 also includes certain other amendments to improve the effectiveness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024. The Company is currently evaluating ASU 2023-09 and the impact it may have to the Company’s financial position, results of operations, cash flow or disclosures.
Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations, cash flows or disclosures.
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(2) |
Acquisitions and Dispositions |
In the first quarter of 2025, the Company recognized a gain of $
In the first quarter of 2024, the Company sold
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(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 billings |
$ | $ | ||||||
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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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( |
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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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Taxes |
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Lease operating costs |
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Other |
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Total |
$ | $ | ||||||
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(4) |
Long-Term Debt: |
On July 5, 2022, the Company and its lenders entered into a Fourth Amended and Restated Credit Agreement (the “2022 Credit Agreement”) with a maturity date of June 1, 2026. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $
Effective February 9, 2024, the Company and its lenders entered into the Second Amendment to the 2022 Credit Agreement. This amendment included an increase of the Borrowing Base from $
Effective July 29, 2024, the Company and its lenders entered into the Third Amendment to the 2022 Credit Agreement, increasing the Borrowing Base from $
Effective December 20, 2024, the Company and its lenders entered into the Fourth Amendment to the 2022 Credit Agreement, reaffirming the credit agreement at $
As of June 30, 2025, the Company had $
|
(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
Operating lease costs for the six months ended June 30, 2025 and 2024 were $
All current leases have been included within the current balance sheet and the Company has not entered into any new leases since the reporting date of June 30, 2025. Rent expense for office space for the six months ended June 30, 2025 and 2024 was $
The payment schedule for the Company’s operating lease obligations as of June 30, 2025 is as follows:
|
(Thousands of dollars) |
Operating |
|||
|
2025 (remainder of year) |
$ | |||
|
2026 |
||||
|
2027 |
||||
|
2028 |
||||
|
Total undiscounted lease payments |
$ | |||
|
Less: Amount associated with discounting |
( |
) | ||
|
Total net operating lease liabilities |
$ | |||
|
Less: Current portion of net operating lease liabilities |
||||
|
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, 2025 is as follows:
|
(Thousands of dollars) |
June 30, |
|||
|
Asset retirement obligation at December 31, 2024 |
$ | |||
|
Net wells placed on production |
||||
|
Liabilities settled |
( |
) |
||
|
Accretion of discount |
||||
|
Asset retirement obligation at June 30, 2025 |
$ | |||
|
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 credit adjusted risk free 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, 2025 and 2024, 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.
|
(9) |
Segment Information: |
The Company operates in one industry – oil and gas exploration, development, operation and servicing. Net income (loss) before income taxes is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources and assessing performance. This measure allows our management to effectively evaluate our operating performance and compare the results between periods. The CODM is our Chief Executive Officer.
|
(10) |
Earnings Per Share: |
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the consolidated financial statements:
|
Six Months Ended June 30, |
||||||||||||||||||||||||
|
2025 |
2024 |
|||||||||||||||||||||||
|
Net |
Weighted |
Per |
Net |
Weighted |
Per |
|||||||||||||||||||
|
Basic |
$ | $ | $ | $ | ||||||||||||||||||||
|
Effect of dilutive securities: |
||||||||||||||||||||||||
|
Options |
763,209 | |||||||||||||||||||||||
|
Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
|
Three Months Ended June 30, |
||||||||||||||||||||||||
|
2025 |
2024 |
|||||||||||||||||||||||
|
Net |
Weighted |
Per |
Net |
Weighted |
Per |
|||||||||||||||||||
|
Basic |
$ | $ | $ | $ | ||||||||||||||||||||
|
Effect of dilutive securities: |
||||||||||||||||||||||||
|
Options |
||||||||||||||||||||||||
|
Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
|
(11) |
Subsequent Event: |
On July 4, 2025, President Trump signed the One Big Beautiful Bill Act (the “OBBBA”) into law. Among other things, the OBBBA indefinitely extends the 100% first-year depreciation allowance on qualified property placed in service after January 19, 2025, includes favorable modifications to the business interest expense limitation, and otherwise extends and enhances certain key provisions of the Tax Cuts & Jobs Act. The OBBBA has multiple effective dates with respect to its various provisions, with certain provisions effective in 2025. We are currently assessing the impacts of the OBBBA on our consolidated financial statements, and while we do not expect it to have a material impact on our results of operations, we do expect it to provide a benefit to our cash flows from operating activities.
|
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. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements of our Annual Report.
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 it could 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. We currently have no derivative contracts and do not intend to enter into future derivative contracts unless required to do so for our bank line of credit, or we believe we would significantly benefit from near term price stability.
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 17,138 gross (9,622 net) acres, 89.3% 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 additional 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 4,021 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.
Recent Activity
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, 2024. 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. 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. 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 |
||||||||||||||||||||||||||||||||||||
|
2022 |
4,143 | 2,497 | 22,277 | 10,353 | 3,028 | 1,833 | 9,030 | 6,366 | 7,171 | 4,330 | 31,307 | 16,719 | ||||||||||||||||||||||||||||||||||||
|
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 | ||||||||||||||||||||||||||||||||||||
|
(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. |
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, 2024, 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 |
||||||||||||||||||||||||
|
2022 |
$ | 320,146 | $ | 192,688 | $ | 200,790 | $ | 118,081 | $ | 520,936 | $ | 310,769 | $ | 66,233 | $ | 244,536 | ||||||||||||||||
|
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 | ||||||||||||||||
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 SEC specifications and 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.
Natural gas prices, based on the twelve-month average of the first-of-the-month Henry Hub index price, were $2.13 per MMBtu in 2024 as compared to $2.64 per MMBtu in 2023 and $6.36 per MMBtu in 2022. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month average spot price, were $75.48 per barrel in 2024 as compared to $78.22 per barrel in 2023, and $93.67 per barrel in 2022. When applying these prices to our reserves, they are further adjusted to take into consideration differentials.
While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.
District Information and Recent Activity
The following table represents certain reserves and well information as of December 31, 2024.
|
Gulf |
Mid- |
West |
Other |
Total |
||||||||||||||||
|
Proved Reserves as of December 31, 2024 (MBoe) |
||||||||||||||||||||
|
Developed |
452 | 2,643 | 17,159 | 35 | 20,288 | |||||||||||||||
|
Undeveloped |
— | — | 6,224 | — | 6,224 | |||||||||||||||
|
Total |
452 | 2,643 | 23,383 | 35 | 26,512 | |||||||||||||||
|
Average Net Daily Production (Boe per day) |
143 | 806 | 13,749 | 9 | 14,707 | |||||||||||||||
|
Gross Productive Wells (Working Interest and ORRI Wells) |
124 | 518 | 652 | 219 | 1,513 | |||||||||||||||
|
Gross Productive Wells (Working Interest Only) |
73 | 359 | 543 | 75 | 1,050 | |||||||||||||||
|
Net Productive Wells (Working Interest Only) |
24 | 159 | 274 | 4 | 461 | |||||||||||||||
|
Gross Operated Productive Wells |
28 | 117 | 315 | — | 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 73 producing wells (24 net) in the Gulf Coast region as of December 31, 2024, of which 28 wells are operated by us. Average net daily production in our Gulf Coast Region at year-end 2024 was 143 Boe. At December 31, 2024, we had 452 MBoe of proved reserves in the Gulf Coast region, which represented 1.7% of our total proved reserves. We maintain an acreage position of over 7,468 gross (4,699 net) acres in this region, primarily in Colorado, Newton, and Polk counties. In October of 2024, on the San Pedro Ranch in Dimmit County, Texas, we finished plugging-out all of our wells, removing all surface equipment, and reclaiming the land. With assistance from an operator in the area, we were able to do so at minimal expense to the Company. By plugging out our wells on this property we were able to extinguish a substantial amount of future plugging liability.
Currently, 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 fraced in May 2025. Currently, the well is producing approximately 1700 Mcfd along with 75 Bcpd and 130 Bwpd.
In the Segno Field of Polk County, Texas, the Wing #16 was completed in May 2025 at an estimated cost of $400,000. First gas sales occurred in June 2025. Currently, the well is producing 240 Mcfd, 3 Bcpd, and 50 Bwpd. Gulf Coast also plans to recomplete the Sarah F. Wing #80 in the Segno field of Polk County, Texas, at an expense of approximately $100,000.
Mid-Continent Region
Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2024, we had 359 producing wells (159 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 2024 was 806 Boe. On December 31, 2024, we had 2,643 MBoe of proved reserves in the Mid-Continent area, representing 10% of our total proved reserves. We maintain an acreage position of approximately 45,075 gross (10,050 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 participated with Ovintiv Mid-Continent in drilling of two 2-mile-long horizontal wells which were spud in March 2025 and completed in May 2025. Our share of these wells are around 3.1% and the total investment will be on the order of $402,000. We have also elected to participate with Devon in Kingfisher County, Oklahoma in drilling two 2-mile-long horizontal wells which should be spud in August 2025. Our share of these wells are around 9.95% and total investment will be on the order of $1,414,000.
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, 2025, we had 543 wells (274 net) in the West Texas area, of which 304 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 2024 was 13,749 Boe. On December 31, 2024, we had 23,383 MBoe of proved reserves in the West Texas area, or 88.3% of our total proved reserves. We maintain an acreage position of approximately 17,138 gross (9,622 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing eight 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.
Horizontal development of our leasehold acreage has continued at a fast pace, particularly in West Texas, where in 2024 we participated with Double Eagle, Pioneer, Civitas, and ConocoPhillips in the drilling and completion of 56 new horizontal wells targeting the Wolfcamp and Spraberry producing intervals. There are at least six pay intervals (“benches”) being developed in the Midland Basin, from the deeper Wolfcamp “D” up through the shallower Middle Spraberry. The economic variability from one area to another and from one well to another depends on geologic properties (thickness, porosity, permeability, and hydrocarbon maturity), lateral length, stimulation, and oil price, as well as the economies of scale and therefore cost advantages often achieved by the more active operators. Under our leasehold acreage in the Midland Basin, several of these benches have either never been tested, or not yet developed, however, near our acreage, some of these benches have just recently been aggressively developed. We estimate that our acreage in Reagan, Upton, and Martin counties has the potential for as many as 100 drilling locations for these benches that we believe will likely be drilled in the next several years. In particular, under our large acreage position in Reagan County, only the Wolfcamp “A” and “B” intervals have been developed so far, along with a one-well test of the Wolfcamp “D” on one block, which is encouraging. We, therefore, see significant potential for near-term development of one or more productive intervals in the Wolfcamp “D”, Jo Mill, Lower Sprabbery, and Middle Spraberry.
In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County. In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing $37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our “Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000. Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,800. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals.
In addition to this activity, in June of 2024, we began participation with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract. Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and will in total invest approximately $40.5 million. In addition, in November of 2024, in Reagan County, we began participating with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total will invest roughly $23 million through completion of production facilities. Each of these 15 horizontals are on production as of June 1, 2025. By the end of the second quarter of 2025, therefore, the Company has invested approximately $64 million in these additional 21 horizontal wells.
In the second half of 2025, we are anticipating the start of 15 new horizontals in the Midland Basin of West Texas operated by Double Eagle on our “Full House” tract in Reagan County in which the Company will participate with approximately 27% interest and invest $30.1 million. Drilling has been completed on all 15 wells and completion is in progress as of August 1, 2025. These wells are expected to be on production late third quarter of this year. In addition to the Reagan County activity, the company is participating in eight (8) “Horseshoe” wells in Midland County with Vital Energy. Drilling activity with these wells began in the second quarter and will complete in early third quarter of 2025 with production early fourth quarter. The Company has an average of 8.2% interest in these eight (8) wells and will invest approximately $5.4 million in Midland County.
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 will soon be put forward for the drilling of between 36 and 45 new horizontals that will target the Wolfcamp “D” pay zone in Reagan County and perhaps an additional test well or two in one or more of the other undeveloped pay horizons. In this future activity, we would expect to invest in excess of $100 million. In addition, the Company has identified 25 horizontal locations across our acreage in Upton and Martin counties that could be drilled in this same time frame. These additional wells will require an investment of approximately $76 million. In total, therefore, with approximately $48 million to be invested in the various wells drilling or to begin drilling in 2025, the $100 million in Wolfcamp “D” development, and the $76 million in 25 other near-term wells expected in the 2026-2027 timeframe, we anticipate investing approximately $224 million in horizontal drilling in West Texas over the next several years.
RESULTS OF OPERATIONS
We reported net income of $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, as compared to $31.1 million, or $17.31 basic earnings per share, and $19.7 million, or $11.08 basic earnings per share for the six and three months ended June 30, 2024, respectively. Current year net income reflects increases in production and oil commodity prices combined with lower gas and natural gas liquid commodity prices over the three and six months ended June 30, 2025. The significant components of income and expense are discussed below.
Oil, gas and NGLs sales decreased $21.9 million, or 35.4% to $39.8 million for the three months ended June 30, 2025, from $61.7 million for the three months ended June 30, 2024, and $13.7 million, or 13.6% to $87.1 million for the six months ended June 30, 2025, from $100.7 million for the six months ended June 30, 2024. Sales vary due to changes in volumes of production sold and realized commodity prices.
The following tables summarize the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2025 and 2024 (excluding realized gains and losses from derivatives).
|
Six months ended June 30, |
||||||||||||||||
|
2025 |
2024 |
Increase / |
Increase / |
|||||||||||||
|
Barrels of Oil Produced |
1,057,000 | 1,126,000 | (69,000 | ) | (6.13 | )% | ||||||||||
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Average Price Received |
$ | 63.24 | $ | 79.51 | $ | (16.27 | ) | (20.46 | )% | |||||||
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Oil Revenue (In 000’s) |
$ | 66,844 | $ | 89,533 | $ | (22,689 | ) | (25.34 | )% | |||||||
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Mcf of Gas Sold |
4,815,000 | 2,886,000 | 1,929,000 | 66.84 | % | |||||||||||
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Average Price Received |
$ | 1.26 | $ | 0.50 | $ | 0.76 | 152.00 | % | ||||||||
|
Gas Revenue (In 000’s) |
$ | 6,072 | $ | 1,440 | $ | 4,632 | 321.67 | % | ||||||||
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Barrels of Natural Gas Liquids Sold |
835,000 | 480,000 | 355,000 | 73.96 | % | |||||||||||
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Average Price Received |
$ | 16.94 | $ | 20.29 | $ | (3.35 | ) | (16.50 | )% | |||||||
|
Natural Gas Liquids Revenue (In 000’s) |
$ | 14,146 | $ | 9,739 | $ | 4,407 | 45.25 | % | ||||||||
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Total Oil & Gas Revenue (In 000’s) |
$ | 87,062 | $ | 100,712 | $ | (13,650 | ) | (13.55 | )% | |||||||
|
Three months ended June 30, |
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|
2025 |
2024 |
Increase / |
Increase / |
|||||||||||||
|
Barrels of Oil Produced |
600,000 | 695,000 | (95,000 | ) | (13.67 | )% | ||||||||||
|
Average Price Received |
$ | 56.96 | $ | 80.91 | $ | (23.95 | ) | (29.60 | )% | |||||||
|
Oil Revenue (In 000’s) |
$ | 34,178 | $ | 56,234 | $ | (22,056 | ) | (39.22 | )% | |||||||
|
Mcf of Gas Sold |
2,424,000 | 1,729,000 | 695,000 | 40.20 | % | |||||||||||
|
Average Price Received |
$ | 0.02 | $ | 0.05 | $ | (0.03 | ) | (64.54 | )% | |||||||
|
Gas Revenue (In 000’s) |
$ | 43 | $ | 82 | $ | (39 | ) | (47.56 | )% | |||||||
|
Barrels of Natural Gas Liquids Sold |
381,000 | 274,000 | 107,000 | 39.05 | % | |||||||||||
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Average Price Received |
$ | 14.74 | $ | 19.61 | $ | (4.87 | ) | (24.82 | )% | |||||||
|
Natural Gas Liquids Revenue (In 000’s) |
$ | 5,617 | $ | 5,374 | $ | 243 | 4.52 | % | ||||||||
|
Total Oil & Gas Revenue (In 000’s) |
$ | 39,838 | $ | 61,690 | $ | (21,852 | ) | (35.42 | )% | |||||||
Oil and gas production expense decreased $2.3 million, or 18.5% to $10.1 million for the three months ended June 30, 2025 from $12.4 million for the three months ended June 30, 2024, and $1.8 million, or 8.4% to $19.7 million for the six months ended June 30, 2025 from $21.5 million for the six months ended June 30, 2024. These changes reflect costs related to the new wells that have been placed on production offset by cost savings related to wells that have been plugged.
Production and ad valorem taxes decreased $1.9 million, or 51.4% to $1.8 million for the three months ended June 30, 2025 from $3.7 million for the three months ended June 30, 2024, and $1.6 million, or 23.9% to $5.1 million for the six months ended June 30, 2025 from $6.7 million for the six months ended June 30, 2024. These decreases reflect the changes in oil, natural gas and natural gas liquids revenues in the related periods.
Field service income decreased $0.9 million or 31.0% to $2.0 million for the three months ended June 30, 2025 from $2.9 million for the three months ended June 30, 2024 and $2.2 million, or 34.9% to $4.1 million for the six months ended June 30, 2025 from $6.3 million for the six months ended June 30, 2024. Workover rig services and hot oil treatments represent the bulk of our field service operations. These changes reflect the sale of our South Texas service company in Q3 2024.
Field service expense decreased $1.3 million or 52.0% to $1.2 million for the three months ended June 30, 2025 from $2.5 million for the three months ended June 30, 2024 and $2.2 million, or 41.5% to $3.1 million for the six months ended June 30, 2025 from $5.3 million for the six months ended June 30, 2024. Field service expenses primarily consist of wages and vehicle operating expenses. These changes reflect the sale of our South Texas service company in Q3 2024.
Depreciation, depletion and amortization expense increased $3.5 million or 20.2% to $20.8 million for the three months ended June 30, 2025 from $17.3 million for the three months ended June 30, 2024 and increased $13.5 million, or 48.9% to $41.1 million for the six months ended June 30, 2025 from $27.6 million for the six months ended June 30, 2024. This increase is due to an increase in production volumes added from new wells being placed on-line since June 30, 2024, and due to changes in the overall depletion rate resulting from the costs of these wells being added to the depletion base plus revisions to overall reserves in place.
General and administrative expense decreased $0.9 million or 23.1% to $3.0 million for the three months ended June 30, 2025 from $3.9 million for the three months ended June 30, 2024 and decreased $1.0 million, or 14.5% to $5.9 million for the six months ended June 30, 2025 from $6.9 million for the six months ended June 30, 2024. These changes are primarily due to lower employee compensation, benefits and other corporate costs.
Interest expense increased $0.5 million or 250.0% to $0.7 million for the three months ended June 30, 2025 from $0.2 million for the three months ended June 30, 2024 and increased $0.8 million, or 160.0% to $1.3 million for the six months ended June 30, 2025 from $0.5 million for the six months ended June 30, 2024.This increase reflects the higher borrowings during the six months of 2025 under our revolving credit agreement.
Income tax expense for the June 30, 2025 and 2024 periods 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 2025, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2025 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 2025, can be summarized as follows: in 2023 we invested $96 million in 35 horizontals, in 2024 we invested $113 million in 48 horizontals, and in 2025, we expect to invest $98 million in 44 horizontals as discussed under district information and recent activity. Therefore, in total, since January 2023 and through 2025, the Company will have invested roughly $307 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 gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.
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. As of August 14, 2025, the Company is not required to enter into any hedge agreements. 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 $115 million. As of August 14, 2025, there were no outstanding borrowings under this line. 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 new borrowing base review is currently in progress and no change in the borrowing base is expected. 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 commodity 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 natural gas prospects available, the market for oilfield services, and oil and natural 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 since the last quarter of 2025 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.
|
2025 Month |
Number of |
Average Price |
Maximum Under |
|||||||||
|
April |
11,970 | $ | 173.20 | 114,044 | ||||||||
|
May |
2,000 | $ | 192.17 | 112,044 | ||||||||
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June |
3,000 | $ | 161.85 | 109,044 | ||||||||
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Total/Average |
16,970 | $ | 173.43 | |||||||||
|
(1) |
In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, June 13, 2018 and June 7, 2023, the Board of Directors of the Company approved an additional 500,000, 200,000 and 300,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 4,000,000 shares have been authorized to date under this program. Through June 30, 2025, a total of 3,890,956 shares have been repurchased under this program for $113,454,862 at an average price of $29.16 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:
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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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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 19, 2025 |
/s/ Charles E. Drimal, Jr. |
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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 19, 2025 |
Beverly A. Cummings |
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Executive Vice President |
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Principal Financial Officer |
EXHIBIT 31.1
CERTIFICATIONS
I, Charles E. Drimal, Jr., Chief Executive Officer of PrimeEnergy Resources Corporation, certify that:
|
1. |
I have reviewed this Form 10-Q for the quarter ended June 30, 2025 of PrimeEnergy Resources Corporation; |
|
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
|
3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
|
4. |
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
(a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
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(b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
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(c) |
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
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(d) |
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
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5. |
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
|
(a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
|
(b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
August 19, 2025
|
/s/ Charles E. Drimal, Jr. |
|
Charles E. Drimal, Jr. |
|
Chief Executive Officer |
|
PrimeEnergy Resources Corporation |
EXHIBIT 31.2
CERTIFICATIONS
|
I, |
Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Resources Corporation, certify that: |
|
1. |
I have reviewed this Form 10-Q for the quarter ended June 30, 2025 of PrimeEnergy Resources Corporation; |
|
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
|
3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
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4. |
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
(a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
|
(b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
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(c) |
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
|
(d) |
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
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5. |
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
|
(a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
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(b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
August 19, 2025
|
/s/ Beverly A. Cummings |
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Beverly A. Cummings |
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Chief Financial Officer |
|
PrimeEnergy Resources Corporation |
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-Q for the period ending June 30, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles E. Drimal Jr., Chief Executive Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
|
(1) |
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
|
(2) |
The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
|
/s/ Charles E. Drimal, Jr. |
|
Charles E. Drimal, Jr. Chief Executive Officer |
|
August 19, 2025 |
EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-Q for the period ending June 30, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
|
(1) |
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
|
(2) |
The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
|
/s/ Beverly A. Cummings |
|
Beverly A. Cummings Chief Financial Officer |
|
August 19, 2025 |