SEC Form 10-Q filed by PrimeEnergy Resources Corporation

PrimeEnergy Resources Corporation

Index to Form 10-Q

September 30, 2024

 

	Page
Definitions of Certain Terms and Conventions Used Herein
Cautionary Statement Concerning Forward-Looking Statements
Part I—Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets – September 30, 2024 and December 31, 2023	1
Consolidated Statements of Income – For the three and nine months ended September 30, 2024 and 2023	2
Consolidated Statements of Equity – For the three and nine months ended September 30, 2024 and 2023	3
Consolidated Statements of Cash Flows – For the nine months ended September 30, 2024 and 2023	4
Notes to Consolidated Financial Statements – September 30, 2024	5-9
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation	10-19
Item 3. Quantitative and Qualitative Disclosures About Market Risk	19
Item 4. Controls and Procedures	19
Part II - Other Information
Item 1. Legal Proceedings	20
Item 1A. Risk Factors	20
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	20
Item 3. Defaults Upon Senior Securities	20
Item 4. Reserved	20
Item 5. Other Information	20
Item 6. Exhibits	21
Signatures	23

 

 

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.

 

●

“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.

 

●

“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 Nine Months Ended September 30, 2024 and 2023

(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 Nine Months Ended September 30, 2024 and 2023

(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

Nine Months Ended September 30, 2024 and 2023

(Thousands of dollars)

 

 

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

 

 

PRIMEENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2024

 

(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, 2023. 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 September 30, 2024, and December 31, 2023, the consolidated results of operations, cash flows and equity for the nine months ended September 30, 2024, and 2023.

 

As of September 30, 2024, 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, 2023. 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.

 

New Pronouncements Issued But Not Yet Adopted:

 

In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around a public entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.

 

(2)	Acquisitions and Dispositions

 

2024 Transactions:

 

In the first quarter of 2024, the Company 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 $55,000.

 

In the third quarter of 2024, acreage transactions included the acquisition of 100.27 net acres in Reagan County for a purchase price of $1,109,785, the sale of 7.8 surface acres in Midland County, Texas for proceeds of $427,760 and the sale of 44.58 net acres of leasehold interest in Roger Mills County Oklahoma for proceeds of $89,159. In New Mexico we sold our working interests in seven properties in Lea and Eddy Counties $220,000. Effective September 1, 2024 the Company sold its interest in Eastern Oil Well Service Company, a south Texas well-servicing business, for net proceeds of $2,800,000, regonizing a gain of $1,921,000.

 

2023 Transactions:

 

In the first quarter of 2023, the Company sold 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.

 

In the second quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320 non-core acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.

 

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In the third quarter of 2023, the Company sold a non-core 38.25-acre leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original

ownership in such wells. In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres.

 

(3)	Additional Balance Sheet Information:

 

Certain balance sheet amounts are comprised of the following:  

 

(Thousands of dollars)		September 30, 2024				December 31, 2023
Accounts Receivable:
Joint interest billing		$	3,340			$	2,560
Trade receivables			1,483				2,345
Oil and gas sales			28,970				14,457
Taxes			1,078				1,458
Other			452				155
			35,323				20,975
Less: Allowance for credit losses			(1,019	)			(674	)
Total		$	34,304			$	20,301
Accounts Payable:
Trade		$	36,574			$	9,847
Royalty and other owners			4,391				4,405
Partner advances			976				946
Other			236				226
Total		$	42,177			$	15,424
Accrued Liabilities:
Compensation and related expenses		$	5,890			$	10,324
Taxes			7,246				929
Lease operating costs			4,540				3,898
Other			381				198
Total		$	18,057			$	15,349

 

(4)	Long-Term Debt:

 

Bank Debt:

 

On July 5, 2022, the Company and its lenders entered into a Fourth Amended and Restated Credit Agreement (the “2022 Credit Agreement”) with a maturity date of June 1, 2026. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $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. 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 January 20, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and the Company of the 2022 Credit Agreement resulted in an adjustment to decrease the amount of the Borrowing Base available from $75 million to $60 million until such time as the next redetermination date as required by the agreement.

 

Effective July 24, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and the Company of the 2022 Credit Agreement resulted in an adjustment to increase the amount of the Borrowing Base available from $60 million to $65 million until such time as the next redetermination date as required by the agreement.

 

As of December 31, 2023, the borrowing base was $65 million and the Company had no outstanding borrowings under the Credit Facility.

 

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.

 

6

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Effective July 29, 2024, the Company and its lenders entered into the Third Amendment to the 2022 Credit Agreement. This amendment included an increase of the Borrowing Base from $85 million to $115 million and will remain in effect until the next scheduled redetermination date in accordance with the Credit Agreement.

 

As of September 30, 2024, the Company had $3 million in outstanding borrowings and $112 million in available 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 8.97%. 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, 2024 and 2023 were $557 thousand and $525 thousand, respectively. Cash payments included in the operating lease cost for the nine months ended September 30, 2024 and 2023 were $592 thousand and $552 thousand, respectively. The weighted-average remaining operating lease terms as of September 2024 and 2023 were 3.0 months and 7.88 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for future payments of $200 thousand in 2024, and $149 thousand in 2025.

 

Rent expense for office space for the nine months ended September 30, 2024 and 2023 was $668 thousand and $522 thousand, respectively.

 

The payment schedule for the Company’s operating lease obligations as of September 30, 2024 is as follows:

 

(Thousands of dollars)		Operating Leases
2024		$	200
2025			149
Total undiscounted lease payments		$	349
Less: Amount associated with discounting			(35	)
Total net operating lease liabilities		$	314
Less: Current portion asset retirement and other long-term obligations			(314	)
Non-current portion included in Other long-term obligations		$	0

 

Asset Retirement Obligation:

 

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2024 is as follows:

 

(Thousands of dollars)		September 30, 2024
Asset retirement obligation at December 31, 2023		$	15,153
Net wells placed on production			70
Liabilities settled			(706	)
Liabilities divested			(137	)
Accretion of discount			514
Asset retirement obligation at September 30, 2024		$	14,894
Less current portion of asset retirement obligations			(316	)
Asset retirement obligations, long-term		$	14,578

 

7

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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, 2024 and 2023, 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)	Financial Instruments

 

Fair Value Measurements:

 

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3.

 

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.

 

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs would not be provided. As of the balance sheet reporting dates of September 30, 2024 and December 31, 2023, the Company had no active derivative instruments.

 

Derivative Instruments:

 

The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity-based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.

 

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The following table sets forth the effect of derivative instruments on the consolidated statements of income for the nine months ended September 30, 2024 and 2023:

 

				Amount of gain/loss recognized in income
(Thousands of dollars)		Location of gain/loss recognized in income		2024				2023
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts		Gain on derivative instruments, net			0				235
Crude oil commodity contracts		Gain on derivative instruments, net			0				179
				$	0			$	414

 

(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,
		2024												2023
		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		$	53,127				1,778,224			$	29.88			$	22,220				1,859,084			$	11.95
Effect of dilutive securities:
Options (a)			0				760,044								0				758,674
Diluted		$	53,127				2,538,268			$	20.93			$	22,220				2,617,758			$	8.49

 

		Three Months Ended September 30,
		2024												2023
		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		$	22,076				1,747,727			$	12.63			$	10,720				1,834,709			$	5.84
Effect of dilutive securities:
Options (a)			0				760,904												759,215
Diluted		$	22,076				2,508,631			$	8.80			$	10,720				2,593,924			$	4.13

 

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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.

 

OVERVIEW

 

We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas and Oklahoma. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun. In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators. In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that may possibly have future value for producers in the area. We also hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres in Prattville, Alabama. There is currently no debt on the shopping center and it has approximately $700,000 of working capital on its balance sheet. 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.

 

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities, and the operational performance of our producing properties. 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.

 

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities when used to manage commodity price risk. Our most recent contracts expired in March of 2023 and we currently do not intend to use future derivative contracts unless required by our bank loan.

 

We derive our revenue and cash flow principally from the sale of oil, natural gas, and Natural Gas Liquids (NGLs). As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas, and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI, or other major market pricing. The market price for oil, natural gas, and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas, and NGLs. Index prices for oil, natural gas, and NGLs are higher than in the recent past, however, prices 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.

 

 

The Company is actively developing non-producing 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 (9,484 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry, Jo Mill and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 190 additional horizontal wells. In Oklahoma, we maintain an acreage position of approximately 45,715 gross (10,102 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,355 net acres in these counties hold additional resource potential that could support the drilling of as many as 38 new horizontal wells based on an estimate of four wells per section, two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $30 million at an average 10% ownership level, but in this current natural price environment we would not likely participate with a working interest, but would instead sell or farm-out our interest.

 

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

 

The following table represents certain reserves and well information as of December 31, 2023.

 

		Gulf Coast				Mid- Continent				West Texas				Other				Total
Proved Reserves as of December 31, 2023 (MBoe)
Developed			563				2,210				10,778				7				13,558
Undeveloped			0				0				15,488				0				15,488
Total			563				2,210				26,266				7				29,046
Average Net Daily Production (Boe per day)			173				831				6,172				4				7,181
Gross Productive Wells (Working Interest and ORRI Wells)			114				511				647				222				1,494
Gross Productive Wells (Working Interest Only)			72				361				541				144				1,118
Net Productive Wells (Working Interest Only)			21				132				275				5				433
Gross Operated Productive Wells			28				128				334				0				490
Gross Operated Water Disposal, Injection and Supply wells			5				39				8				0				52

 

In the West Texas region, we have field service groups 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, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

 

Gulf Coast Region

 

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Yegua and Wilcox formations at depths ranging from 3,000 to 12,500 feet. We had 114 producing wells (21 net) in the Gulf Coast region as of December 31, 2023, of which 28 wells were operated by us. Average net daily production in our Gulf Coast Region at year-end 2023 was 173 Boe. At December 31, 2023, we had 563 MBoe of proved reserves in the Gulf Coast region, which represented 2% 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. At this time, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed, but we do have plans for the recompletion of one well in the Segno field of Polk County, in which the Company has a 72.5% working interest.

 

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, 2023, we had 511 producing wells (132 net) in the Mid-Continent area, of which 128 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 2023 was 831 Boe. On December 31, 2023, we had 2,210 MBoe of proved reserves in the Mid-Continent area, representing 8% of our total proved reserves. We maintain an acreage position of approximately 45,715 gross (10,102 net) acres in this region, primarily in Canadian, Kingfisher, Garfield, 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 Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian and Woodford formations. These Oklahoma counties that are our primary focus for horizontal development are Canadian, Kingfisher, Grady, and Garvin.

 

 

West Texas Region

 

West Texas activities are concentrated in the Permian Basin in Texas. The oil and gas in this basin are produced primarily from five intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2023, we had 647 wells (275 net) in the West Texas area, of which 334 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 2023 was 6,172 Boe. On December 31, 2023, we had 26,267 MBoe of proved reserves in the West Texas area, or 90% of our total proved reserves. We maintain an acreage position of approximately 17,138 gross (9,484 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, three hot oiler trucks, and one kill truck. Oil field support is provided for drilling and workover operations both to third-party operators as well as for our own operated wells and locations.

 

As of September 30, 2024, the Company was participating in the completion of 6 horizontal wells in Upton County, Texas with an average 47.52% interest. In total, we expect to spend approximately $35 million in these horizontals and their associated facilities. are in the process of being completed and expect to be on production in the first quarter of 2025

 

In 2024, we have completed 56 new horizontal wells, investing approximately $141 million. We are also preparing to invest approximately $84 million in another 30 horizontal wells to be drilled and completed in 2025. In addition, we have identified 21 horizontal locations for future development in West Texas that we anticipate to be drilled in the 2026-2027 timeframe and would require a net investment of approximately $69 million.

 

Reserves

 

All of our interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2023. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our districts consist of degreed engineers and geologists with over twenty-five years of industry experience and between ten and twenty-five years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over thirty years of experience, holds a Bachelor’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. 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)
2021			5,386				2,882				23,902				12,252				0				0				0				0				5,386				2,882				23,902				12,252
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

 

(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.

 

During 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells. Also in 2021, the Company participated with Ovintiv USA for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma. Twelve of these thirteen horizontal wells were successfully completed and placed into production in the fourth quarter of 2021. One of the Ovintiv wells had a casing leak issue and has been temporarily abandoned. The Company invested approximately $32 million in these thirteen wells. In addition, in 2021, the Company added minor reserves through over-riding royalty interest in two wells drilling and completed in Grady County, Oklahoma.

 

 

At December 31, 2021, the Company had 159 Mboe of proved developed shut-in reserves attributable to three horizontals drilled and completed in Canadian County, Oklahoma, but not yet online at year-end. These reserves were converted to proved producing in the first quarter of 2022. At year-end 2021, we did not include proved undeveloped reserves in our reserve report because we had not yet received definitive drilling proposals from third-party operators for the more than fifteen horizontal wells that we planned to participate in located primarily in West Texas.

 

In 2022, the Company participated in eight horizontal wells that were drilled and completed; four located in Irion County, West Texas, operated by SEM Operating Company, in which we have 10.13% interest, and four located in Canadian County, Oklahoma, operated by Ovintiv USA, in which we have an average 9% interest. Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022. In addition, the Company added reserves through 15 wells in which we have various minor over-riding royalty interest. Eight of these wells are located in West Texas and seven are located in Oklahoma.

 

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontals located in West Texas operated by three different operators. In Martin County, we participated with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest and had capital investment of $12.1 million. In Reagan County, we participated with Hibernia Energy III (now Civitas Resources) in 10 two-mile horizontals with 25% interest and an investment of approximately $25.6 million. Also in Reagan County, we participated with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying a net capital outlay of $23.4 million. All twenty of these West Texas wells were completed and online in the second quarter of 2023.

 

At year-end 2022, the Company had 6,366 Mboe of proved undeveloped reserves attributable to 25 horizontal wells, including the 20 West Texas wells spud in the fourth quarter of 2022 described above, three Ovintiv “Redhead” wells not yet drilled in Canadian County, Oklahoma, and two Apache “MT. Moran” wells planned in Upton County, Texas.

 

In 2023, the Company participated with five operators in the drilling and completion of 35 horizontal wells: 32 of these are located in West Texas and three are located in Oklahoma. In total, including the cost of facilities, the Company invested approximately $91 million, 99% of which is attributable to the wells in West Texas where we have been drilling horizontal wells targeting various proven pay intervals in the Wolfcamp and Spraberry formations. At December 31, 2023, we had 12 wells completed but not producing that were all brought into production in January of 2024. These 12 wells account for 1,278 MBOE of proved developed reserves at year-end. In addition, as of December 31, 2023, the Company was in the process of drilling and completing 34 wells in West Texas, 28 of which are considered proved undeveloped, and six of which are considered probable undeveloped. The year-end reserve report includes only proved reserves, therefore expected reserves from the six probable undeveloped wells are not 999 included in the reserve report.

 

At year-end 2023, the Company had 15,488 MBOE of proved undeveloped reserves that are attributable to 52 undeveloped wells, 28 of which were in the process of being drilled or completed at year-end.

 

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, 2023, 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
2021		$	275,227			$	171,906			$	—			$	—			$	275,227			$	171,906			$	36,100			$	135,806
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

 

The PV10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

 

 

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

 

While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

 

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $2.64 per MMBtu in 2023 as compared to $6.36 per MMBtu in 2022 and $3.60 per MMBtu in 2021. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month average spot price, were $78.22 per barrel in 2023 as compared to $93.67 per barrel in 2022, and $66.56 per barrel in 2021. Since January 1, 2023, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

 

RECENT ACTIVITIES

 

The Company’s activities include development and exploratory drilling. Our strategy is to develop the Company’s extensive oil and gas reserves primarily through horizontal drilling. This 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. Through 2024, we will focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our capital budget for the year is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures. 

 

Horizontal development of our leasehold acreage has continued at a fast pace, particularly in West Texas, where in 2023 we participated with Double Eagle, Apache, Civitas, and ConocoPhillips in the drilling and completion of 32 new horizontal wells, and in Oklahoma in 2023, participated with Ovintiv USA with a minor interest in three 3-mile-long horizontal laterals. Now in 2024, we are on track to complete 56 new horizontal wells and participate in an additional six wells expected to be spud in the fourth quarter.

 

In 2023, the Company participated with five operators in the drilling and completion of 35 horizontal wells: 32 of these are located in West Texas and three in Oklahoma. In total, including the cost of facilities, the Company invested approximately $91 million in these wells, 99% of which is attributable to the wells in West Texas where we have been targeting proven pay intervals in the Wolfcamp and Spraberry formations.

 

In Reagan County, in 2023, we participated with Hibernia Energy II (Now Civitas) in ten 2-mile-long horizontals having 25% interest and investing $25.6 million in our “Brynn” wells that began production in April 2023. Also in Reagan County, we participated with DE IV, LLC (Double Eagle) in 15 horizontals: five 2-mile-long laterals in which we have nearly 50% interest, called the “Prime East” wells that were placed on production in May 2023, another six 2-mile-long laterals in which we have 7% interest, our “Studley AV” wells, that were brought on production in December 2023, and four 2.5-mile laterals with 20% interest, part of our “Studley CKO” wells, that were completed in December 2023 but not put online until January 2024. All twelve “Studley CKO” wells were brought on production in January 2024 and were included in the 2023 year-end reserve report as proved developed non-producing.

 

 

Also in 2023, in Upton County, Texas we participated for 50% interest in two 3-mile-long horizontals operated by Apache. These wells were brought into production in October 2023 and we invested approximately $17 million in these wells and their associated facilities. In Martin County, Texas we participated with ConocoPhillips for 20.8% interest in five 2.5-mile-long horizontal laterals, investing approximately $12 million. These five wells were completed and brought online in September 2023. Also in 2023, in Oklahoma, the Company joined Ovintiv USA in the drilling of three 3-mile-long horizontals located in Canadian County with 2% interest, invested approximately $645,000.

 

In the first quarter of 2024, in Reagan County, Texas, with Double Eagle, we have completed eight “Studley CKO” 2.5-mile horizontals with an average 19.7% interest, investing $15.5 million, as well as three “O’Bannon” horizontals with 8.2% interest and two “Pink Floyd” horizontals with less than 1% interest. These five are also 2.5-mile-long laterals and in them we have invested approximately $2.6 million. Also in the first quarter, participating with Civitas Resources, an additional nine 2-mile-long horizontals were completed. In these “Christi” wells we have approximately 40% working interest and invested $29 million. All 12 “Studley CKO” wells were brought into production in the first quarter.

 

In the Second Quarter of 2024, the Company completed nine additional wells in Reagan County, Texas: three more “O’Bannon” wells, and six “Kramer” wells. In these nine 2.5-mile-long-horizontals, the Company has an average 8.3% ownership and invested approximately $7.5 million. These nine wells, along with the three “O’Bannon” wells completed in the first quarter, were brought on line in April. Also, in April nine “Christi” wells were brought on production. In addition to these wells brought on production in April, the Company is participating with 37.5% interest in five more “Christi” wells operated by Civitas and with 50% interest in six “Prime West” wells operated by Double Eagle. The estimated cost for the remaining five “Christi” wells and the six Prime West wells is $14 million and $23.9 million respectively. These 11 wells were stimulated and put on production in May. In April of this year, participating with Double Eagle, the Company spud 12 wells in Reagan County, Texas. In these 12 “Honey RF” wells the Company has 50% working interest and has invested approximately $43.6 million. These wells were all completed in the third quarter and on production by mid-September 2024.

 

In May 2024, together with Double Eagle, we spud a 2-mile-long horizontal test well in Reagan County, Texas targeting the Wolfcamp D interval. In this well the Company has approximately 6% interest. The well had a respectable initial production rate of 1000 barrels of oil per day, but declined rather quickly in the first two months, so it may be three months or more of additional production before we know if this well has confirmed the Wolfcamp D as an economically viable target in the immediate area. Civitas Resources has also been targeting the Wolfcamp D interval and in their November 2024 third quarter reports have highlighted strong results from their 16 new Wolfcamp D wells in Reagan and Upton counties. Both Civitas Resources and Diamondback Energy have stated plans for additional Wolfcamp D drilling in southern Midland Basin. This additional drilling target for the Company would potentially set-up the development of as many as 36 horizontals on our acreage in Reagan County. In such a development program, the Company would have a range of interest from 6% to 50%, with an average of approximately 29%, and investment of approximately $94 million.

 

In total, in 2024, we completed 56 new horizontal wells, investing approximately $141 million and the six wells with Apache in Upton County, Texas that are in the process of being completed are expected to come on line after the first of the year. We are also actively investing or preparing to invest approximately $84 million in 30 new horizontal wells, including six 3-mile-long horizontals with Apache now in the process of being completed in Upton County, Texas, that are expected to be completed and put on production in 2025. In addition, we have identified 21 horizontal locations for future development of the Upper Wolfcamp and Spraberry, primarily in Martin and Upton Counties that we anticipate will be drilled in the 2026-2027 timeframe which would require a net investment of approximately $69 million. In total, we anticipate investing more than $300 million in horizontal development in West Texas from January 2024 through December 2027. The Wolfcamp D target interval could potentially add 36 drilling locations and investment potential of $94 million to what is already expected through 2027.

 

In the Permian Basin of West Texas, we maintain an acreage position of approximately 17,138 gross (9,484 net) acres, 97% of which is located in Reagan, Upton, and Martin counties of Texas where our current West Texas horizontal drilling activities are focused. In addition to the wells currently being drilled or completed, we believe this acreage has the resource potential to support the drilling of as many as 190 future horizontal wells.

 

In Oklahoma, we are focused on the development of our reserves in Canadian, Kingfisher, Grady, and Garvin counties where we have approximately 4,073 net leasehold acres in the Scoop/Stack Play. Of this acreage, we believe 2,355 net leasehold acres hold significant additional resource potential that could support the drilling of as many as 38 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out, receiving cash and retaining an over-riding royalty interest. Regarding 15 newly drilled wells in 2023, in which we elected to farm our working interest and retain an ORRI, five were completed and put on production in March 2024, another five were completed and put on production in September 2024, and the remaining five were completed and brought on production mid to late October 2024. Thus far in 2024, there have been no additional development wells proposed.

 

 

RESULTS OF OPERATIONS

 

We reported net income of $53.13 million, or $29.88 per share, and $22.10 million, or $12.63 per share for the nine and three months ended September 30, 2024, respectively, as compared to $22.22 million, or $11.95 per share and $10.72 million, or $5.84 per share for the nine and three months ended September 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 nine months ended September 30, 2024. The significant components of income and expense are discussed below.

 

Oil, gas and NGLs sales increased $31.99 million, or 99.88% to $64.01 million for the three months ended September 30, 2024, from $32.02 million for the three months ended September 30, 2023, and $88.99 million, or 117.53% to $164.72 million for the nine months ended September 30, 2024, from $75.72 million for the nine months ended September 30, 2023. These increases reflect the additional wells placed on line during the nine months ended September 30, 2024.

 

The following tables summarize the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2024 and 2023 (excluding realized gains and losses from derivatives).  

 

						Nine months ended September 30,
		2024				2023				Increase / (Decrease)				Increase / (Decrease)
Barrels of Oil Produced			1,883,000				814,000				1,069,000				131.33	%
Average Price Received		$	77.39			$	76.10			$	1.29				1.70	%
Oil Revenue (In 000’s)		$	145,727			$	61,948			$	83,779				135.24	%
Mcf of Gas Sold			5,030,000				2,766,000				2,264,000				81.85	%
Average Price Received		$	0.41			$	1.97			$	(1.56	)			(79.19	)%
Gas Revenue (In 000’s)		$	2,078			$	5,452			$	(3,374	)			(61.89	)%
Barrels of Natural Gas Liquids Sold			874,000				412,000				462,000				112.14	%
Average Price Received		$	19.35			$	20.20			$	(0.85	)			(4.21	)%
Natural Gas Liquids Revenue (In 000’s)		$	16,915			$	8,323			$	8,592				103.23	%
Total Oil & Gas Revenue (In 000’s)		$	164,720			$	75,723			$	88,997				117.53	%

 

 

						Three months ended September 30,
		2024				2023				Increase / (Decrease)				Increase / (Decrease)
Barrels of Oil Produced			757,000				323,000				434,000				134.37	%
Average Price Received		$	74.23			$	81.73			$	(7.50	)			(9.18	)%
Oil Revenue (In 000’s)		$	56,194			$	26,402			$	29,792				112.84	%
Mcf of Gas Sold			2,144,000				1,081,000				1,063,000				98.41	%
Average Price Received		$	0.30			$	2.29			$	(1.99	)			(86.90	)%
Gas Revenue (In 000’s)		$	638			$	2,472			$	(1,834	)			(74.19	)%
Barrels of Natural Gas Liquids Sold			394,000				161,000				233,00				144.72	%
Average Price Received		$	18.21			$	19.56			$	(1.35	)			(6.90	)%
Natural Gas Liquids Revenue (In 000’s)		$	7,176			$	3,149			$	4,027				127.88	%
Total Oil & Gas Revenue (In 000’s)		$	64,008			$	32,023			$	31,985				99.88	%

 

Oil, Natural Gas and NGL Derivatives. We do not apply hedge accounting to any of our commodity-based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of income. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. Unrealized and realized losses by product are presented in the table below for the nine months ended September 30, 2024 and 2023. The Company has no active derivative instruments as of the filing of this report.

 

		Nine Months Ended September 30, 2024				Nine Months Ended September 30, 2023
Oil derivatives – gains, net		$	0			$	179
Natural gas derivatives – gains, net			0				235
Total gains on oil and natural gas derivatives		$	0			$	414

 

 

Average oil and gas prices received for the nine months ended September 30, 2024 and 2023, including the impact of derivatives were: 

 

		2024				2023
Average sales prices per barrel of oil		$	77.39			$	75.42
Average sales prices per MCF of gas		$	0.41			$	1.98
Average sales price Natural Gas Liquids		$	19.35			$	20.18

 

Oil and gas production expense increased $5.0 million, or 63.29% to $12.9 million for the three months ended September 30, 2024 from $7.9 million for the nine months ended September 30, 2023, and $13.2 million, or 62.26% to $34.4 million for the nine months ended September 30, 2024 from $21.2 million for the nine months ended September 30, 2023. These changes reflect the cost savings related to wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production.

 

Production and ad valorem taxes increased $1.2 million, or 83.39% to $2.6 million for the three months ended September 30, 2024 from $1.4 million for the three months ended September 30, 2023, and $4.0 million, or 75.23% to $9.3 million for the Nine months ended September 30, 2024 from $5.3 million for the Nine months ended September 30, 2023. These increased reflect the increases in oil and natural gas liquid revenues partially offset by lower gas revenues in the related periods.

 

Field service income decreased $0.7 million or 20.38% to $2.6 million for the third quarter 2024 from $3.3 million for the third quarter 2023 and $2.5 million, or 21.63% to $8.9 million for the nine months ended September 30, 2024 from $11.4 million for the nine months ended September 30, 2023. Workover rig services, hot oil treatments, saltwater hauling, and disposal represent the bulk of our field service operations. These changes reflect decreases in equipment utilization.

 

Field service expense decreased $0.06 million or 1.99% to $3.10 million for the third quarter 2024 from $3.16 million for the third quarter 2023 and $1.3 million, or 13.65% to $8.4 million for the nine months ended September 30, 2024 from $9.7 million for the nine months ended September 30, 2023. Workover rig services, hot oil treatments, saltwater hauling, and disposal represent the bulk of our field service operations. These changes reflect decreases in equipment utilization.

 

Depreciation, depletion and amortization expense increased $22.9 million or 100.57% to $45.8 million for the nine months ended September 30, 2024, from $22.8 million for the nine months ending September 30, 2023, and increased $9.3 million, or 104.29% to $18.2 million for the third quarter 2024 from $8.9 million for the third quarter 2023. These increases reflect the expense related to the new wells placed on production during the nine months ended September 30, 2024.

 

General and administrative expense increased $2.8 million, or 34.34% to $10.8 million for the nine months ended September 30, 2024 from $8.1 million for the nine months ended September 30, 2023, and $ 1.2 million, or 45.28% to $3.9 million for the three months ended September 30, 2024 from $2.7 million for the three months ended September 30, 2023. This increase is primarily due to employee compensation, benefits and other corporate costs.

 

Interest expense increased $0.3 million to $0.4 million for the third quarter 2024 from $0.1 million for the third quarter 2023, and increased $0.4 million to $0.8 million for the nine months ended September 30, 2024 from $0.4 million for the nine months ended September 2023. This increase reflects the higher interest and fee rates combined with borrowings throughout the nine months of 2024 under our revolving credit agreement.

 

Income tax expense for September 30, 2024 and 2023 periods varied due to the change in net income

 

LIQUIDITY AND CAPITAL RESOURCES

 

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2024, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2024 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.

 

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 determined at the end of each quarter, the Company is not required to enter into any hedge agreements. As of November 14, 2024, 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 November 14, 2024, the Company’s outstanding borrowings under this line are $22.1 million. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for December 2024. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.

 

The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

 

The Company has a stock repurchase program in place, spending under this program during the first nine months of 2024 was $10.2 million. The Company expects continued spending under the stock repurchase program in 2024.

 

The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower-risk wells with a high probability of success and higher-risk wells with greater economic potential. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.

 

In 2023, the Company spud 58 wells, fifteen of these were completed by year-end, and the remaining 43 wells will all be complete in 2024: 22 of these were completed in the first quarter of 2024, 20 were completed in the second quarter of 2024, and one was completed in the third quarter of 2024. Also in the second quarter of 2024, the Company participated with Double Eagle in the drilling of a new well spud in May that was completed in mid-June. The Company invested approximately $27 million in the 15 wells completed in 2023, $50.6 million in the 22 wells completed in the first quarter of 2024, and $46 million in the 21 wells completed in the second quarter of 2024. All but three wells drilled in 2023 are horizontal wells drilled in West Texas, primarily in Reagan County. In the third quarter of 2024, the Company completed 12 new “Honey RF” horizontals in Reagan County, Texas in which we have 50% working interest and have invested approximately $43.6 million.

 

In addition, the Company is participating in six three-mile-long horizontals in Upton County, Texas operated by Apache Corporation that are in various stages of completion. In these six wells, the Company has an average of 47.5% interest and through completion will invest approximately $35 million.

 

In total, the Company has invested $141 million in 56 wells that have all been completed by early September 2024. In addition, we are currently investing $35.2 million in six horizontal wells operated by Apache in Upton County, Texas that in the process of being completed. We expect to invest an additional $48.4 million in 24 new horizontal wells in West Texas drilled and completed in 2025.

 

During 2023, to supplement cash flow and finance our future drilling programs, the Company sold 368 net mineral acres as well as 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.

 

In the second quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320 non-core acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.

 

 

In the third quarter of 2023, the Company sold a non-core 38.25-acre leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original ownership in such wells. In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres. In the fourth quarter of 2023, the Company sold 136 surface acres in Oklahoma for net proceeds of $306,000 and in Midland Texas sold 9.35 net acres for proceeds of $280,423.

 

Proceeds from these sales in 2023, along with our cash flow, were used to eliminate the Company’s outstanding bank debt as of March 31, 2023.

 

In the first quarter of 2024, the Company sold 48 net acres in Lea County, New Mexico, along with minor working interest in 23 wells, receiving gross proceeds of $375,600, and in the second quarter of 2024, the Company sold an additional 12 net acres in Lea County for proceeds of $150,600. Also in the second quarter of 2024, in addition to the 12 acres mentioned above, we sold 2.29 surface acres in Odessa, Texas for $68,000.

 

On July 1st, 2024 the company sold six wells in New Mexico in exchange for future plugging liabilities. With this sale completed, the company is no longer an operator in the state of New Mexico.

 

In the third quarter of 2024, the Company sold 7.8 surface acres in Midland County, Texas for proceeds of $427,760 and divested of 44.58 net leasehold acres in Roger Mills County Oklahoma for total proceeds of $89,159. In addition, we divested of all of our working interest in the state of New Mexico which included six operated properties in Lea County and minor working interest in one non-operated well in Eddy County. These divestments were in exchange for $220,000 and future plugging obligations. In addition, in the third quarter, the Company sold its south Texas well-servicing business, Eastern Oil Well Service Company and two saltwater disposal wells for $2,800,000.

 

As noted above, as of November 14, 2024, the Company had $22.1 million in outstanding borrowings and $92.9 million in availability under this facility.

 

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 during the first nine months of 2024 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 was no purchase of equity securities by the Company during the period covered by this report. The following table details the Company’s purchase of shares for the nine months ended September 30, 2024.

 

2024 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)
January			5,059			$	102.74				268,585
February			6,711			$	96.54				261,874
March			18,085			$	92.96				243,789
April			2,452			$	101.39				241,337
May			2,972			$	105.50				238,365
June			22,767			$	100.82				215,598
July			7,505			$	117.67				208,093
August			12,079			$	129.14				196,014
September			15,500			$	134.87				180,514
Total/Average			93,130			$	109.95

 

---

(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 September 30, 2024, a total of 3,819,486 shares have been repurchased under this program for $100,227,444 at an average price of $26.24 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

 

 

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 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 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 (filed 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 (filed herewith).
97.1	PrimeEnergy Resources Corporation Compensation Recoupment (CLAWBACK) Policy, filed as exhibit 97.1 of PrimeEnergy Resources Corporation 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)
November 14, 2024	/s/ Charles E. Drimal, Jr.
	Charles E. Drimal, Jr.
	President
	Principal Executive Officer
	/s/ Beverly A. Cummings
November 14, 2024	Beverly A. Cummings
	Executive Vice President
	Principal Financial Officer