pnrg20250930

pnrg20250930_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2025

☐	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 0-7406

PrimeEnergy Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware

84-0637348

(State or other jurisdiction of

incorporation or organization)

(I.R.S. employer

Identification No.)

9821 Katy Freeway, Houston, Texas 77024

(Address of principal executive offices)

(713) 735-0000

(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:

Title of each class

Trading

Symbol(s)

Name of each exchange

on which registered

Common Stock, $0.10 par value

PNRG

NASDAQ

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. Yes ☒ No ☐

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). Yes ☒ No ☐

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.

Large Accelerated Filer	☐	Accelerated Filer	☐

Non-Accelerated Filer	☒	Smaller Reporting Company	☒

		Emerging growth company	☐

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 ☐ No ☒

The number of shares outstanding of each class of the Registrant’s Common Stock as of November 12, 2025 was: Common Stock, $0.10 par value 1,635,000 shares.

PrimeEnergy Resources Corporation

Index to Form 10-Q

September 30, 2025

	Page

Definitions of Certain Terms and Conventions Used Herein
Cautionary Statement Concerning Forward-Looking Statements
Part I—Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – September 30, 2025 (Unaudited) and December 31, 2024	1
Condensed Consolidated Statements of Income (Unaudited) – For the three and nine months ended September 30, 2025 and 2024	2
Condensed Consolidated Statements of Equity (Unaudited) – For the three and nine months ended September 30, 2025 and 2024	3
Condensed Consolidated Statements of Cash Flows (Unaudited) – For the nine months ended September 30, 2025 and 2024	4
Notes to Condensed Consolidated Financial Statements – September 30, 2025	5-8
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation	9-15
Item 3. Quantitative and Qualitative Disclosures About Market Risk	15
Item 4. Controls and Procedures	15
Part II - Other Information
Item 1. Legal Proceedings	16
Item 1A. Risk Factors	16
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	16
Item 3. Defaults Upon Senior Securities	16
Item 4. Reserved	16
Item 5. Other Information	16
Item 6. Exhibits	17
Signatures	18

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except share data)

	September 30, 2025			December 31, 2024
	Unaudited
ASSETS
Current Assets
Cash and cash equivalents	$	3,689		$	2,549
Accounts receivable:
Accounts receivable		19,509			24,752
Less Allowance for credit losses		(414	)		(414	)
		19,095			24,338
Prepaid obligations		1,242			1,372
Other current assets		10			11
Total Current Assets		24,036			28,270
Property and Equipment
Oil and gas properties, at cost		837,659			773,330
Less: Accumulated depletion, depreciation and amortization		(532,367	)		(479,424	)
		305,292			293,906
Field and office equipment, at cost		13,073			14,643
Less: Accumulated depreciation		(11,338	)		(12,712	)
		1,735			1,931
Total Property and Equipment, Net		307,027			295,837
Other Assets		955			515
Total Assets	$	332,018		$	324,622

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	27,114		$	16,329
Accrued property cost		6,290			7,578
Accrued liabilities		10,535			25,514
Due to related parties		57			34
Current portion of asset retirement and other long-term obligations		1,273			200
Total Current Liabilities		45,269			49,655
Long-Term Bank Debt		-			4,000
Asset Retirement Obligations, net of current portion		12,640			13,799
Deferred Income Taxes		59,310			53,405
Other Long-Term Obligations		1,014			838
Total Liabilities and Contingencies		118,233			121,697
Commitments and Contingencies - Note 6
Equity
Common stock, $.10 par value; 2025 and 2024: Authorized and Issued 2,810,000 shares, outstanding 2025: 1,642,500 shares, outstanding 2024: 1,708,470 shares		281			281
Paid-in capital		7,555			7,555
Retained earnings		283,998			261,073
Treasury stock, at cost; 2025: 1,167,500 shares; 2024: 1,101,530 shares		(78,049	)		(65,984	)
Total Equity		213,785			202,925
Total Liabilities and Equity	$	332,018		$	324,622

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

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – Unaudited

Three and Nine Months Ended September 30, 2025 and 2024

(Thousands of dollars, except per share amounts)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues:
Oil	$	34,807	$	56,194	$	101,651	$	145,727
Natural gas		1,968		638		8,040		2,078
Natural gas liquids		5,619		7,176		19,765		16,915
Field service income		2,270		2,657		6,390		8,967
Interests and other income, net		1,306		15		1,545		172
Gain on disposition of assets, net		-		2,775		619		3,411
Total revenues		45,970		69,455		138,010		177,270

Costs and expenses:
Oil and gas production		10,447		12,878		30,101		34,424
Production and ad valorem taxes		2,408		2,650		7,498		9,301
Field service		2,028		3,103		5,121		8,376
Depreciation, depletion and amortization		14,101		18,231		55,242		45,845
Accretion of discount on asset retirement obligations		166		172		501		514
General and administrative		3,039		3,943		8,913		10,863
Interest		482		414		1,782		865
Total costs and expenses		32,671		41,391		109,158		110,188

Income before income tax provision		13,299		28,064		28,852		67,082
Income tax provision		2,736		5,988		5,927		13,955
Net income	$	10,563	$	22,076	$	22,925	$	53,127

Net income per share attributable to common stockholders:
Basic	$	6.41	$	12.63	$	13.75	$	29.88
Diluted	$	4.38	$	8.80	$	9.43	$	20.93
Weighted average shares outstanding:
Basic		1,648,406		1,747,727		1,667,428		1,778,224
Diluted		2,410,878		2,508,631		2,430,409		2,538,268

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

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY – Unaudited

Three and Nine Months Ended September 30, 2025 and 2024

(Thousands of dollars, except share amounts)

	Common Stock				Additional
	Shares Outstanding		Common Stock		Paid-In Capital		Retained Earnings		Treasury Stock			Total Equity
Balance at December 31, 2024		2,810,000	$	281	$	7,555	$	261,073	$	(65,984	)	$	202,925
Purchase of 36,000 shares, at cost		-		-		-		-		(7,095	)		(7,095	)
Net income		-		-		-		9,134		-			9,134
Balance at March 31, 2025		2,810,000	$	281	$	7,555	$	270,207	$	(73,079	)	$	204,964
Purchase of 16,970 shares, at cost		-		-		-		-		(2,943	)		(2,943	)
Net income		-		-		-		3,228		-			3,228
Balance at June 30, 2025		2,810,000	$	281	$	7,555	$	273,435	$	(76,022	)	$	205,249
Purchase 13,000 shares, at cost		-		-		-		-		(2,027	)		(2,027	)
Net income		-		-		-		10,563		-			10,563
Balance at September 30, 2025		2,810,000	$	281	$	7,555	$	283,998	$	(78,049	)	$	213,785

	Common Stock				Additional
	Shares Outstanding		Common Stock		Paid-In Capital		Retained Earnings		Treasury Stock			Total Equity
Balance at December 31, 2023		2,810,000	$	281	$	7,555	$	205,669	$	(52,555	)	$	160,950
Purchase of 29,855 shares, at cost		-		-		-		-		(2,849	)		(2,849	)
Net income		-		-		-		11,319		-			11,319
Balance at March 31, 2024		2,810,000	$	281	$	7,555	$	216,988	$	(55,404	)	$	169,420
Purchase of 28,191 shares, at cost		-		-		-		-		(2,857	)		(2,857	)
Net income		-		-		-		19,732		-			19,732
Balance at June 30, 2024		2,810,000	$	281	$	7,555	$	236,720	$	(58,261	)	$	186,295
Purchase of 35,084 shares, at cost		-		-		-		-		(4,533	)		(4,533	)
Net income		-		-		-		22,076		-			22,076
Balance at September 30, 2024		2,810,000	$	281	$	7,555	$	258,796	$	(62,794	)	$	203,838

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

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Nine Months Ended September 30, 2025 and 2024

(Thousands of dollars)

	2025			2024
Cash Flows from Operating Activities:
Net Income	$	22,925		$	53,127
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		55,242			45,845
Accretion of discount on asset retirement obligations		501			514
Gain on sale and exchange of assets		(619	)		(3,411	)
Provision for deferred income taxes		5,905			8,077
Changes in assets and liabilities:
Accounts receivable		5,243			(14,003	)
Due to related parties		23			(52	)
Prepaids obligations		130			(757	)
Other current assets		1			33
Accounts payable		10,784			26,753
Accrued property costs		-			(26,131	)
Accrued liabilities		(14,979	)		2,708
Right of use and other assets		-			(701	)
Other long-term liabilities		(614	)		-
Net Cash Provided by Operating Activities		84,542			92,002

Cash Flows from Investing Activities:
Capital expenditures		(67,956	)		(98,395	)
Proceeds from sale of properties and equipment		619			4,153
Net Cash Used in Investing Activities		(67,337	)		(94,242	)

Cash Flows from Financing Activities:
Purchase of stock for treasury		(12,065	)		(10,239	)
Proceeds from long-term bank debt		79,500			57,500
Repayment of long-term bank debt and other long-term obligations		(83,500	)		(54,500	)
Net Cash Used in Financing Activities		(16,065	)		(7,239	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,140			(9,479	)
Cash and Cash Equivalents at the Beginning of the Period		2,549			11,061
Cash and Cash Equivalents at the End of the Period	$	3,689		$	1,582

Supplemental Disclosures:
Income taxes paid	$	6,676		$	101
Interest paid	$	2,021		$	782

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

PRIMEENERGY RESOURCES CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 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 condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s consolidated balance sheets as of September 30, 2025, and December 31, 2024, the consolidated results of operations, cash flows and equity for the nine months ended September 30, 2025, and 2024.

As of September 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.

In the third quarter of 2024, the company sold 47 net acres in Roger Mills County, Oklahoma, receiving gross proceeds of $93,850 and retained ORRI on acreage.

(3)

Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)	September 30, 2025		December 31, 2024
Accounts Receivable:
Joint interest billings	$	1,154	$	2,413
Trade receivables		827		958
Oil and gas sales		16,201		21,211
Other		1,327		170
Total	$	19,509	$	24,752
Accounts Payable:
Trade	$	22,943	$	12,038
Royalty and other owners		3,812		3,607
Other		359		684
Total	$	27,114	$	16,329
Accrued Liabilities:
Compensation and related expenses	$	4,796	$	10,668
Taxes		2,719		9,524
Lease operating costs		2,200		4,263
Other		820		1,059
Total	$	10,535	$	25,514

(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 2022 Credit 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 September 30, 2025, the Company had no outstanding borrowings and $115 million in availability under the credit facility. As of November 12, 2025, the Company had $20 million in outstanding borrowings and $95 million in availability under the credit facility. The funds have been split between borrowings types using SOFR or prime rate instruments with our effective rate between 7.4% and 9.5%.

(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 9.5%. 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 nine months ended September 30, 2025 and 2024 were $583 thousand and $557 thousand, respectively. Cash payments included in the operating lease cost for the nine months ended September 30, 2025 and 2024 were $614 thousand and $592 thousand, respectively. The weighted-average remaining operating lease terms as of September 2025 and 2024 were 8.5 months and 3.0 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for future payments of $206 thousand for the remainder of 2025, $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 September 30, 2025. Rent expense for office space for the nine months ended September 30, 2025 and 2024 was $670 thousand and $668 thousand, respectively.

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

(Thousands of dollars)	Operating Leases
2025	$	206
2026		291
2027		127
2028		27

Total undiscounted lease payments	$	651
Less: Amount associated with discounting		(75	)
Total net operating lease liabilities	$	576
Less: Current portion asset retirement and other long-term obligations		413
Non-current portion included in Other long-term obligations	$	163

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2025 is as follows:

(Thousands of dollars)	September 30, 2025
Asset retirement obligation at December 31, 2024	$	13,867
Net wells placed on production		67
Liabilities divested		(935	)
Accretion of discount		501
Asset retirement obligation at September 30, 2025	$	13,500
Less current portion of asset retirement obligations		860
Asset retirement obligations, long-term	$	12,640

The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.

(6)

Contingent Liabilities:

The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

(7)

Stock Options and Other Compensation:

In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 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.

(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:

	Nine Months Ended September 30,
	2025						2024
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	22,925		1,667,428	$	13.75	$	53,127		1,778,224	$	29.88
Effect of dilutive securities:
Options				762,981						760,044

Diluted	$	22,925		2,430,409	$	9.43	$	53,127		2,538,268	$	20.93

	Three Months Ended September 30,
	2025						2024
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	10,563		1,648,406	$	6.41	$	22,076		1,747,727	$	12.63
Effect of dilutive securities:
Options				762,472						760,904

Diluted	$	10,563		2,410,878	$	4.38	$	22,076		2,508,631	$	8.80

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, 96.1% 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 4,015 net leasehold acres in the Scoop/Stack Play.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and the availability of funds under our revolving credit facility.

District Information and 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

(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.

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 1100 Mcfd along with 40 Bcpd and 100 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 160 Mcfd, 1 Bcpd, and 35 Bwpd. Gulf Coast will soon install gas lift/plunger lift to boost production. In the first quarter of 2026, Gulf Coast also plans to recomplete the Sarah F. Wing #80 in the Segno field 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 43,837 gross (10,062 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.

Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Scoop and Stack plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian and Woodford formations. In Canadian County, Oklahoma we 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 is approximately 3.1% and the total investment will be approximately $402,000. We have also participated with Devon in Kingfisher County, Oklahoma to drill two 2-mile-long horizontal wells which were spud July 2025 and are presently being completed, therefore, we anticipate these wells to be producing in November 2025. Our share of these wells is approximately 9.95% and total investment will be approximately $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 September 30, 2025, we had 543 wells (274 net) in the West Texas area, of which 296 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 approximately a 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 September 30, 2025 and the Company has invested approximately $64 million in these additional 21 horizontal wells.

During the third quarter of 2025, we participated in the drilling and completion of 15 horizontal wells in the Midland Basin of West Texas operated by Double Eagle on our “Full House” tract in Reagan County. Drilling and completion has been completed and as of the end of the third quarter 2025 each of the 15 wells were on production. The company participated with approximately 27% interest, investing approximately $30.1 million. 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 2025 and completed in the third quarter of 2025 with production early fourth quarter 2025. The Company has an average of 8.2% interest in these eight (8) wells and investing 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 in the future will 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 $22.93 million, or $13.75 per share, and $10.56 million, or $6.41 per share for the nine and three months ended September 30, 2025, respectively, as compared to $53.13 million, or $29.88 per share and $22.08 million, or $12.63 per share for the nine and three months ended September 30, 2024, respectively. Current year net income reflects increases in gas and NGL combined with lower oil and natural gas liquid commodity prices over the three and nine months ended September 30, 2025. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales decreased $21.61 million, or 33.77% to $42.39 million for the three months ended September 30, 2025, from $64.01 million for the three months ended September 30, 2024, and decreased $35.26 million, or 21.41% to $129.46 million for the nine months ended September 30, 2025, from $164.72 million for the nine months ended September 30, 2024. Sales vary due to changes in volumes of production and realized commodity prices.

The following tables summarize the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2025 and 2024 (excluding realized gains and losses from derivatives).

			Nine months ended September 30,
	2025		2024		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Sold		1,562,000		1,883,000		(321,000	)		(17.05	)%
Average Price Received

SEC Form 10-Q filed by PrimeEnergy Resources Corporation