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Definitions of Certain Terms and Conventions Used Herein

 

Within this Report, the following terms and conventions have specific meanings:

 

Measurements.  

●

“Bbl” means a standard barrel containing 42 United States gallons.

 

●

“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.

 

●

“BOEPD” means BOE per day.

 

●

“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.

 

●

“MBbl” means one thousand Bbls.

 

●

“MBOE” means one thousand BOEs.

 

●

“Mcf” means one thousand cubic feet and is a measure of gas volume.

 

●

“MMcf” means one million cubic feet.

 

Indices.

 

●

“Brent” means Brent oil price, a major trading classification of light sweet oil that serves as a benchmark price for oil worldwide.

 

●

“WAHA” is a benchmark pricing hub for West Texas gas.

 

●

“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.

 

●

“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.

 

●

“DD&A” means depletion, depreciation and amortization.

 

●

“ESG” means environmental, social and governance.

 

●

“GAAP” means accounting principles generally accepted in the United States of America.

 

●

“GHG” means greenhouse gases.

 

●

“LNG” means liquefied natural gas.

 

●

“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.

 

●

“NYMEX” means the New York Mercantile Exchange.

 

●

“OPEC” means the Organization of Petroleum Exporting Countries.

 

●

“PrimeEnergy” or the “Company” means PrimeEnergy Resources Corporation and its subsidiaries.

 

●

“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.

 

 

●

“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.

 

(i)

The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average 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.

 

●

“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.

 

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii)

Undrilled locations can be classified as having 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.

 

(iii)

Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

●

“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.

 

●

“SEC” means the United States Securities and Exchange Commission.

 

●

“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.

 

●

“U.S.” means United States.

 

●

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.

 

●

“WASP” means weighted average sales price.

 

●

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

 

 

Item 1.

FINANCIAL STATEMENTS

 

 

PRIMEENERGY RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except share data)

 

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)

 

 

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)

 

 

 

 

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) 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements

 

 

PRIMEENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2025

 

(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.

 

(2)	Acquisitions and Dispositions

 

In the first quarter of 2025, the Company recognized a gain of $619,000 on the disposition of a workover rig related to our service company that was fully depreciated.

 

In the first quarter of 2024, the Company sold 48 net acres in Lea County, New Mexico, along with minor working interest in 23 non-operated wells, receiving gross proceeds of $375,600, and in the second quarter of 2024, sold an additional 12 net acres in Lea County for proceeds of $150,600. Also in the second quarter of 2024, we farmed out certain acreage in east Texas for $54,800.

 

(3)	Additional Balance Sheet Information:

 

Certain balance sheet amounts are comprised of the following:  

(Thousands of dollars)		June 30, 2025				December 31, 2024
Accounts Receivable:
Joint interest billings		$	1,812			$	2,413
Trade receivables			839				958
Oil and gas sales			26,653				21,211
Other			29				170
			29,333				24,752
Less: Allowance for credit losses			(414	)			(414	)
Total		$	28,919			$	24,338
Accounts Payable:
Trade		$	3,636			$	12,038
Royalty and other owners			3,841				3,607
Partner advances			311				511
Other			9				173
Total		$	7,797			$	16,329
Accrued Liabilities:
Compensation and related expenses		$	4,605			$	10,668
Taxes			3,070				9,524
Lease operating costs			4,033				4,263
Other			978				1,059
Total		$	12,686			$	25,514

 

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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 $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s consolidated financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The initial borrowing base of the agreement was $75 million and adjusted to $65 million in July 2023. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2022Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements. 

 

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 $65 million to $85 million.

 

Effective July 29, 2024, the Company and its lenders entered into the Third Amendment to the 2022 Credit Agreement, increasing the Borrowing Base from $85 million to $115 million.

 

Effective December 20, 2024, the Company and its lenders entered into the Fourth Amendment to the 2022 Credit Agreement, reaffirming the credit agreement at $115 million and extending maturity to 2028. The Borrowing base will remain in effect until either the next scheduled Redetermination Date, June 2025, or the date the Borrowing Base is next adjusted in accordance with the Credit Agreement. As of December 31, 2024, the Company had $4 million in outstanding borrowings and $111 million in availability. The prime rate in effect for December 2024, was 7.50%. The $4 million in outstanding borrowings was considered prime rate borrowings, and were subject to utilization percentage of 2.25%. The effective rate for this borrowing balance at December 31, 2024, was 9.75%.

 

As of June 30, 2025, the Company had $12 million in outstanding borrowings and $103 million in available under the credit facility. The funds outstanding were considered prime rate borrowings and were subject to an effective rate of 9.75%. As of August 14, 2025, the company had no outstanding borrowings and $115 million in availability under the credit facility.

 

(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 9.50%. Certain leases may contain variable costs above the minimum required payments and are not included in the right-of-use assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required.

 

Operating lease costs for the six months ended June 30, 2025 and 2024 were $386 thousand and $370 thousand, respectively. Cash payments included in the operating lease cost for the six months ended June 30, 2025 and 2024 were $408 thousand and $391 thousand, respectively. The weighted-average remaining operating lease terms as of June 30, 2025 and 2024 were 8.63 months and 5.19 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for future payments of $412 thousand for the remainder of 2025, and $291 thousand in 2026, $127 thousand in 2027 and $27 thousand in 2028.

 

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 $438 thousand and $441 thousand, respectively.

 

6

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The payment schedule for the Company’s operating lease obligations as of June 30, 2025 is as follows:

 

(Thousands of dollars)		Operating Leases
2025 (remainder of year)		$	412
2026			291
2027			127
2028			27
Total undiscounted lease payments		$	857
Less: Amount associated with discounting			(84	)
Total net operating lease liabilities		$	773
Less: Current portion of net operating lease liabilities			571
Non-current portion included in Other long-term obligations		$	202

 

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, 2025
Asset retirement obligation at December 31, 2024		$	13,867
Net wells placed on production			67
Liabilities settled			(503	)
Accretion of discount			335
Asset retirement obligation at June 30, 2025		$	13,766
Less current portion of asset retirement obligations			859
Asset retirement obligations, long-term		$	12,907

 

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 four 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 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

 

(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.

 

7

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(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 Income (In thousands)				Weighted Average Number of Shares Outstanding				Per Share Amount				Net Income (In thousands)				Weighted Average Number of Shares Outstanding				Per Share Amount
Basic		$	12,362				1,677,096			$	7.37			$	31,051				1,793,640			$	17.31
Effect of dilutive securities:
Options							763,209												759,507
Diluted		$	12,362				2,440,305			$	5.07			$	31,051				2,553,147			$	12.16

 

		Three Months Ended June 30,
		2025												2024
		Net Income (In thousands)				Weighted Average Number of Shares Outstanding				Per Share Amount				Net Income (In thousands)				Weighted Average Number of Shares Outstanding				Per Share Amount
Basic		$	3,228				1,661,916			$	1.94			$	19,732				1,780,593			$	11.08
Effect of dilutive securities:
Options							762,807												759,729
Diluted		$	3,228				2,424,723			$	1.33			$	19,732				2,540,322			$	7.77

  

(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.

 

8

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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 (MBbls)				NGLs (MBbls)				Gas (MMcf)				Total (MBoe)				Oil (MBbls)				NGLs (MBbls)				Gas (MMcf)				Total (MBoe)				Oil (MBbls)				NGLs (MBbls)				Gas (MMcf)				Total (MBoe)
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

 

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(a)	In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.

 

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 Revenue				Present Value 10 Of Future Net Revenue				Future Net Revenue				Present Value 10 Of Future Net Revenue				Future Net Revenue				Present Value 10 Of Future Net Revenue				Present Value 10 Of Future Income Taxes				Standardized Measure of Discounted Cash flow
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 Coast				Mid- Continent				West Texas				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 / (Decrease)				Increase / (Decrease)
Barrels of Oil Produced			1,057,000				1,126,000				(69,000	)			(6.13	)%
Average Price Received		$	63.24			$	79.51			$	(16.27	)			(20.46	)%
Oil Revenue (In 000’s)		$	66,844			$	89,533			$	(22,689	)			(25.34	)%
Mcf of Gas Sold			4,815,000				2,886,000				1,929,000				66.84	%
Average Price Received		$	1.26			$	0.50			$	0.76				152.00	%
Gas Revenue (In 000’s)		$	6,072			$	1,440			$	4,632				321.67	%
Barrels of Natural Gas Liquids Sold			835,000				480,000				355,000				73.96	%
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	%
Total Oil & Gas Revenue (In 000’s)		$	87,062			$	100,712			$	(13,650	)			(13.55	)%

 

						Three months ended June 30,
		2025				2024				Increase / (Decrease)				Increase / (Decrease)
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	%
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.

 

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.

 

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

 

Item 1.

LEGAL PROCEEDINGS

 

None.

 

Item 1A.

RISK FACTORS

 

The Company is a smaller reporting company and no response is required pursuant to this Item.

 

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 Shares				Average Price Paid per share				Maximum Number of Shares that May Yet Be Purchased Under The Program at Month—End (1)
April			11,970			$	173.20				114,044
May			2,000			$	192.17				112,044
June			3,000			$	161.85				109,044
Total/Average			16,970			$	173.43

 

 

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(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.

 

Item 3.

DEFAULTS UPON SENIOR SECURITIES

 

None

 

Item 4.

RESERVED

 

 

Item 5.

OTHER INFORMATION

 

None

 

18

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Item 6.

EXHIBITS

 

The following exhibits are filed as a part of this report:

 

Exhibit No.

 

1.

Financial statements (Index to Consolidated Financial Statements at page F-1 of this Report)

 

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.

 

3.

Exhibits:

 

3.1	Certificate of Incorporation of PrimeEnergy Resources Corporation, as amended and restated of December  21, 2018, (filed as Exhibit 3.1 of PrimeEnergy Resources Corporation Form 8-K on December 27, 2018, and incorporated herein by reference).
3.2	Bylaws of PrimeEnergy Resources Corporation as amended and restated as of April  24, 2020 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form 8-K on April 27, 2020 and incorporated herein by reference).
4.1	PrimeEnergy Resources Corporation Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934, (filed as exhibit 4.1 of PrimeEnergy Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated by reference).
10.18	Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2004).
10.22.6	FOURTH AMENDED AND RESTATED CREDIT AGREEMENT dated as of July  5, 2022, is among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), each of the Lenders from time to time party hereto and CITIBANK, N.A. (in its individual capacity, “Citibank”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”) (filed as exhibit 10.22.6 of PrimeEnergy Resources Corporation Form 10-Q for the Quarter Ended June 30 2022, and incorporated by reference).
10.22.6.1	FIRST AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT, dated as of October  31, 2022 (the “First Amendment Effective Date”), is among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), CITIBANK, N.A., as administrative agent (in such capacity, the “Administrative Agent”) and as Issuing Bank, each Guarantor party hereto and the financial institutions party hereto as Lenders and incorporated by reference.
10.22.6.2	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of February 9, 2024, among PrimeEnergy Resources Corporation, Citibank, N.A., as administrative agent, the guarantors and the lenders party thereto (filed as exhibit 10.22.6.2) of PrimeEnergy Resources Corporation Form 8-K on February 13, 2024, and incorporated by reference.
10.22.6.3	THIRD AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT, dated as of July 29, 2024, among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), CITIBANK, N.A., as administrative agent (in such capacity, the “Administrative Agent”), each Guarantor party hereto, the Existing Lenders and the New Lender (filed as exhibit 10.22.6.3 of PrimeEnergy Resources Corporation Current Report on Form 8-K filed on August 1, 2024, and incorporated by reference.
10.22.6.4	FOURTH AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT, dated as of December 20, 2024, among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), CITIBANK, N.A., as administrative agent (in such capacity, the “Administrative Agent”), each Guarantor party hereto, the Existing Lenders (filed as exhibit 10.22.6.4 of PrimeEnergy Resources Form 10-K for the year ended December 2024, and incorporated by reference)

 

 

19.1	Insider Trading Policy (filed as exhibit 19.1 of PrimeEnergy Resources Form 10-K for the year ended December 2024, and incorporated by reference)
31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
97.1	PrimeEnergy Resources Corporation Compensation Recoupment (CLAWBACK) Policy, (filed as exhibit 97.1 PrimeEnergy Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated by reference).
101.INS	Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)
101.SCH	Inline XBRL Taxonomy Extension Schema Document (filed herewith)
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith)
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)
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.

 

	PrimeEnergy Resources Corporation
	(Registrant)
August 19, 2025	/s/ Charles E. Drimal, Jr.
	Charles E. Drimal, Jr.
	President
	Principal Executive Officer
	/s/ Beverly A. Cummings
August 19, 2025	Beverly A. Cummings
	Executive Vice President
	Principal Financial Officer