10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended March 31, 2023

Or

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

For the Transition Period From                      to                     

Commission File Number 0-7406

PrimeEnergy Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware	84-0637348
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer Identification No.)

9821 Katy Freeway, Houston, Texas 77024

(Address of principal executive offices)

(713) 735-0000

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.10 par value	PNRG	NASDAQ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	☐	Accelerated Filer	☐
Non-Accelerated Filer	☒	Smaller Reporting Company	☒
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The number of shares outstanding of each class of the Registrant’s Common Stock as of May 16, 2023 was: Common Stock, $0.10 par value 1,850,500 shares.

PrimeEnergy Resources Corporation

Index to Form 10-Q

March 31, 2023

	Page
Part I—Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets –March 31, 2023 and December 31, 2022		1
Consolidated Statements of Operations – For the three months ended March 31, 2023 and 2022		2
Consolidated Statements of Equity – For the three months ended March 31, 2023 and 2022		3
Consolidated Statements of Cash Flows – For the three months ended March 31, 2023 and 2022		4
Notes to Consolidated Financial Statements – March 31, 2023		5-10
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		11-19
Item 3. Quantitative and Qualitative Disclosures About Market Risk		20
Item 4. Controls and Procedures		20
Part II - Other Information
Item 1. Legal Proceedings		21
Item 1A. Risk Factors		21
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		21
Item 3. Defaults Upon Senior Securities		21
Item 4. Reserved		21
Item 5. Other Information		21
Item 6. Exhibits		22-23
Signatures		24

2

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars, except share data)

	March 31, 2023			December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents	$	13,723		$	26,543
Accounts receivable, net		11,151			12,147
Prepaid obligations		16,139			32,839
Due from related parties		373			388
Derivative asset		—			210
Other current assets		38			38
Total Current Assets		41,424			72,165
Property and Equipment
Oil and gas properties at cost		584,701			555,280
Less: Accumulated depletion and depreciation		(391,882	)		(385,811	)
		192,819			169,469
Field and office equipment at cost		27,086			27,246
Less: Accumulated depreciation		(22,940	)		(22,728	)
		4,146			4,518
Total Property and Equipment, Net		196,965			173,987
Derivative asset long-term and other assets		951			985
Total Assets	$	239,340		$	247,137
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	15,935		$	11,451
Accrued liabilities		26,135			25,750
Current portion of asset retirement and other long-term obligations		2,172			2,566
Derivative liability short-term		—			1,190
Total Current Liabilities		44,242			40,957
Long-Term Bank Debt		—			11,000
Asset Retirement Obligations		13,708			13,525
Deferred Income Taxes		40,387			39,968
Other Long-Term Obligations		1,988			1,334
Total Liabilities		100,325			106,784
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2023 and 2022: Authorized: 2,810,000 shares, outstanding 2023: 1,869,560; outstanding 2022: 1,901,000 shares		281			281
Paid-in capital		7,555			7,555
Retained earnings		178,976			177,566
Treasury stock, at cost; 2023: 940,440 shares; 2022: 909,000		(47,797	)		(45,049	)
Total Equity		139,015			140,353
Total Liabilities and Equity	$	239,340		$	247,137

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

1

PRIMEENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

Three Months Ended March 31, 2023 and 2022

(Thousands of dollars, except per share amounts)

	2023			2022
Revenues
Oil sales	$	14,578		$	26,305
Natural gas sales		1,752			3,746
Natural gas liquids sales		2,394			3,851
Realized loss on derivative instruments, net		(566	)		(3,819	)
Field service income		3,474			2,958
Unrealized gain (loss) on derivative instruments, net		980			(7,139	)
Other income		38			29
Total Revenues		22,650			25,931
Costs and Expenses
Lease operating expense		7,974			8,719
Field service expense		3,167			2,720
Depreciation, depletion, amortization		6,422			7,008
Accretion of discount on asset retirement obligations		183			170
General and administrative expense		3,102			6,672
Total Costs and Expenses		20,848			25,289
Gain on Sale and Exchange of Assets		51			13,991
Income from Operations		1,853			14,633
Other Income (Expense)
Interest Expense		(182	)		(349	)
Interest Income		114			—
Income Before Provision for Income Taxes		1,785			14,284
Provision for Income Taxes		375			3,142
Net Income	$	1,410		$	11,142
Basic Income Per Common Share	$	0.75		$	5.62
Diluted Income Per Common Share	$	0.53		$	4.07

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

2

PRIMEENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY – Unaudited

Three Months Ended March 31, 2023 and 2022

(Thousands of dollars, except share amounts)

	Shares Outstanding			Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock			Total Equity
Balance at December 31, 2021		1,992,077		$	281	$	7,555	$	128,902	$	(37,647	)	$	99,091
Purchase 11,188 shares of common stock		(11,188	)	$	—	$	—	$	—	$	(833	)	$	(833	)
Net Income		—			—		—		11,142		—			11,142
Balance at March 31, 2022		1,980,889		$	281	$	7,555	$	140,044	$	(38,480	)	$	109,400
Balance at December 31, 2022		1,901,000		$	281	$	7,555	$	177,566	$	(45,049	)	$	140,353
Purchase 31,440 shares of common stock		(31,440	)		—		—		—		(2,748	)		(2,748	)
Net Income		—			—		—		1,410		—			1,410
Balance at March 31, 2023		1,869,560		$	281	$	7,555	$	178,976	$	(47,797	)	$	139,015

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

3

PRIMEENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Three Months Ended March 31, 2023 and 2022

(Thousands of dollars)

	2023			2022
Cash Flows from Operating Activities:
Net Income	$	1,410		$	11,142
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		6,605			7,178
Gain on sale and exchange of assets		(51	)		(13,991	)
Unrealized (gain) loss on derivative instruments, net		(980	)		7,139
Deferred income taxes		419			3,143
Changes in assets and liabilities:
Accounts receivable		996			(6,471	)
Due from related parties		15			(52	)
Prepaids obligations		16,700			565
Other long-term obligations		654			—
Accounts payable		4,484			1,814
Accrued liabilities		385			(1,112	)
Net Cash Provided by Operating Activities		30,637			9,355
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense		(30,149	)		(1,784	)
Proceeds from sale of properties and equipment		440			13,991
Net Cash (Used in) Provided by Investing Activities		(29,709	)		12,207
Cash Flows from Financing Activities:
Purchase of stock for treasury		(2,748	)		(833	)
Repayment of long-term bank debt and other long-term obligations		(11,000	)		(27,000	)
Net Cash (Used in) Financing Activities		(13,748	)		(27,833	)
Net (Decrease) in Cash and Cash Equivalents		(12,820	)		(6,271	)
Cash and Cash Equivalents at the Beginning of the Period		26,543			10,347
Cash and Cash Equivalents at the End of the Period	$	13,723		$	4,076
Supplemental Disclosures:
Interest paid	$	167		$	240

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

4

PRIMEENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2023

(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, 2022. 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 March 31, 2023, and December 31, 2022, the consolidated results of operations, cash flows and equity for the three months ended March 31, 2023, and 2022.

As of March 31, 2023, 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, 2022. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

(2) Acquisitions and Dispositions

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 first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.0 million.

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)	March 31, 2023			December 31, 2022
Accounts Receivable:
Joint interest billing	$	1,821		$	1,806
Trade receivables		1,874			1,762
Oil and gas sales		7,698			8,894
Other		61			21
		11,454			12,483
Less: Allowance for doubtful accounts		(303	)		(336	)
Total	$	11,151		$	12,147
Accounts Payable:
Trade	$	10,146		$	5,142
Royalty and other owners		3,279			3,600
Partner advances		1,112			1,111
Other		1,398			1,598
Total	$	15,935		$	11,451
Accrued Liabilities:
Compensation and related expenses	$	4,665		$	9,743
Property costs		10,933			6,413
Taxes		9,333			9,352
Other		1,204			242
Total	$	26,135		$	25,750

5

(4) Long-Term Debt:

Bank Debt:

The Company maintains a revolving corporate credit facility (the “Credit Facility”) with a group of financial institutions with aggregate loan commitments of $300 million, subject to a borrowing base that is determined semi-annually, with a maturity date of June 1, 2026. As of December 31, 2022, the borrowing base was $75 million and the Company had $11 million outstanding borrowings under the Credit Facility.

The Credit Facility requires 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, and places restrictions on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements. As of March 31, 2023, the Company was in compliance with its debt covenants. Borrowings bear interest, at the option of the Company, based on a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) Adjusted Term SOFR (secured overnight financing rate as administered by the Federal Reserve Bank of New York) for a one-month tenor in effect on such day plus 1.00%, or a Term SOFR. Both options are subject to an additional margin, determined based upon the utilization of the borrowing base then in effect, ranging from 2.25% to 4.25% per annum. The Company also pays commitment fees on undrawn amounts under the Credit Facility of 0.50% per annum. Borrowings under the Credit Facility are secured by substantially all of the Company’s oil and gas properties.

Effective January 20, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and Prime 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.

As of March 31, 2023, the borrowing base was $60 million and the Company had no outstanding borrowings 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. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for office equipment is included in property and equipment, current portion of asset retirement and other long-term obligations this quarter. 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 7.82%. 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. Leases with an initial term of 12 months or less are not recorded on the balance sheet.

Operating lease costs for the three months ended March 31, 2023, and 2022 were $165 thousand and $142 thousand, respectively. Cash payments included in the operating lease cost for the three months ended March 31, 2023, and 2022 were $178 thousand and $150 thousand, respectively. The weighted average remaining operating lease terms as of March 31, 2023, and 2022 were 9.63 months and 12 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for payments of $561,000 in 2023, $275,000 in 2024, and $45,000 in 2025.

Rent expense for office space the quarter ended March 31, 2023 and 2022 was $141,000 and $177,000, respectively.

The payment schedule for the Company’s operating lease obligations as of March 31, 2023 is as follows:

(Thousands of dollars)	Operating Leases
2023	$	561
2024		275
2025		45
Total undiscounted lease payments	$	881
Less: Amount associated with discounting		(63	)
Total net operating lease liabilities	$	818
Less: Current portion included in Current portion of asset retirement and Other Long-Term Obligations		661
Non-Current portion included in Other Long-Term Obligations	$	157

6

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2023 is as follows:

(Thousands of dollars)	March 31, 2023
Asset retirement obligation at December 31, 2022	$	15,443
Liabilities settled		(407	)
Accretion of discount		183
Asset retirement obligation at March 31, 2023	$	15,219
Less current portion of asset retirement obligations		(1,511	)
Asset retirement obligations, long-term	$	13,708

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 March 31, 2023 and 2022, 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 following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at March 31, 2023 and December 31, 2022:

March 31, 2023	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2023
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	—	$	—
Total assets	$	—	$	—	$	—	$	—

7

March 31, 2023	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at March 31, 2023
(Thousands of dollars)
Liabilities
Commodity derivative contracts	$	—	$	—	$	—		$	—
Total liabilities	$	—	$	—	$	—		$	—
December 31, 2022	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2022
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	210		$	210
Total assets	$	—	$	—	$	210		$	210
Liabilities
Commodity derivative contracts	$	—	$	—	$	(1,190	)	$	(1,190	)
Total liabilities	$	—	$	—	$	(1,190	)	$	(980	)

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 LIBOR 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.

8

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 were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2023.

(Thousands of dollars)
Net Liabilities – December 31, 2022	$	(980	)
Total realized and unrealized gains (losses):
Included in earnings (a)		414
Purchases, sales, issuances and settlements		566
Net Liabilities — March 31, 2023	$	—

(a) Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on 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.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at March 31, 2023 and December 31, 2022:

			Fair Value
(Thousands of dollars)	Balance Sheet Location		March 31, 2023		December 31, 2022
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contract		Other current assets	$	—	$	162
Natural gas commodity contract		Other current assets		—		48
Total			$	—	$	210
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term	$	—	$	(931	)
Natural gas commodity contracts		Derivative liability short-term		—		(259	)
Crude oil commodity contracts		Derivative liability long-term		—		—
Natural gas commodity contracts		Derivative liability long-term		—		—
Total			$	—	$	(1,190	)
Total derivative instruments			$	—	$	(980	)

9

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the three months ended March 31, 2023 and 2022:

		Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2023			2022
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net		211			(1,948	)
Crude oil commodity contracts	Unrealized gain (loss) on derivative instruments, net		769			(5,191	)
Natural gas commodity contracts	Realized gain (loss) on derivative instruments, net		24			(620	)
Crude oil commodity contracts	Realized loss on derivative instruments, net		(590	)		(3,199	)
		$	414		$	(10,958	)

(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:

	Quarter Ended March 31,
	2023						2022
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	1,410		1,888,895	$	0.75	$	11,142		1,980,878	$	5.62
Effect of dilutive securities:
Options				758,325						756,544
Diluted	$	1,410		2,647,220	$	0.53	$	11,142		2,737,422	$	4.07

10

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.

OVERVIEW

We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, and Oklahoma. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun. In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators. In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that we believe has 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 $500,000 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 consolidated balance sheets.

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 statements of operations as changes occur in the NYMEX price indices. Our existing derivative instruments expired in March of 2023 and at this time we do not intend to enter into future derivative contracts unless required for our bank line of credit.

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. As mentioned above, our existing 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.

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The Company is actively developing additional reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas the Company maintains an acreage position of approximately 16,139 gross (9,569 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 and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells. In Oklahoma we maintain an acreage position of approximately 47,119 gross (10,297 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 4,113 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 43 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 $33 million at an average 10% ownership level.

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, 2022.

	Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves as of December 31, 2022 (MBoe)
Developed		790		2,549		7,001		13		10,353
Undeveloped		—		110		6,256		—		6,366
Total		790		2,659		13,257		13		16,719
Average Net Daily Production (Boe per day)		227		897		3,257		4		4,385
Gross Productive Wells (Working Interest and ORRI Wells)		150		508		557		151		1,373
Gross Productive Wells (Working Interest Only)		132		383		511		82		1,108
Net Productive Wells (Working Interest Only)		69		169		254		6		498
Gross Operated Productive Wells		89		176		310		—		575
Gross Operated Water Disposal, Injection and Supply wells		7		40		6		—		53

In several of our producing regions 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 Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 150 producing wells (69 net) in the Gulf Coast region as of December 31, 2022, of which 89 wells are operated by us. Average net daily production in our Gulf Coast Region at year-end 2022 was 227 Boe. At December 31, 2022, we had 790 MBoe of proved reserves in the Gulf Coast region, which represented 4.7% of our total proved reserves. We maintain an acreage position of over 8,707 gross (1,215 net) acres in this region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, twenty water transport trucks, two saltwater disposal wells and several trucks and excavating equipment. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations. As of March 31, 2023, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2022, we had 508 producing wells (169 net) in the Mid-Continent area, of which 176 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. Average net daily production

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in our Mid-Continent Region in 2022 was 897 Boe. At December 31, 2022, we had 2,659 MBoe of proved reserves in the Mid-Continent area, representing 16% of our total proved reserves. We maintain an acreage position of approximately 47,120 gross (10,297 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties. Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations.

As of March 31, 2023, in the Mid-Continent region, the Company is participating with 1.96% interest in three 15,000’ long horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc. All three wells have been drilled and are in the process of being completed with production starts expected by the end of the second quarter. The expected reserves of these three wells were included in the 2022 year-end reserve report as proved undeveloped.

West Texas Region

Our West Texas activities are concentrated in the Permian Basin where much of the United States’ oil reserves are produced from the prolific Wolfcamp and Spraberry reservoirs. The oil is West Texas Intermediate Sweet and the produced casing-head gas has a high BTU content making it a source of our natural gas liquids. The oil and gas are primarily from five producing 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, 2022, we had 557 wells (254 net) in the West Texas area, of which 310 wells are operated by us. Average net daily production in Our West Texas Region at year-end 2022 was 3,257 Boe. At December 31, 2022, we had 13,256 MBoe of proved reserves in the West Texas area, or 79.3 % of our total proved reserves. We maintain an acreage position of approximately 16,139 gross (9,569 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. Services, including well service support, site preparation and construction services for drilling and workover operations, are provided to third-party operators as well as utilized in our own operated wells and locations.

As of March 31, 2023, the Company was participating in the drilling of 15 two-mile-long horizontal wells in Reagan County, Texas with 49.7% interest in five wells operated by Double Eagle and 25% interest in ten wells operated by Hibernia Energy. In Upton County, Texas, the Company was also participating with Apache in the drilling of two 3-mile-long horizontals with 47.52% ownership. In Martin County, Texas, the Company is participating with ConocoPhillips in the drilling of five 2.5-mile-long horizontals with 20.83% interest. Combined, we expect to spend approximately $78 million in the drilling and completion of these 22 West Texas horizontals and their associated facilities. These 22 wells and their forecast reserves were included in the 2022 year-end reserve report as proved undeveloped. The 10 wells operated by Hibernia were placed on production in late April 2023 and based on the success of these wells Hibernia has indicated their intent to spud an additional 16 wells on adjacent acreage late in the third quarter of this year. These additional wells are slated to be in production in the first quarter of 2024. Our share of these 16 wells will be between 37.5% and 50% with an average of 41.1% and an investment of approximately $75 million. In addition, Double Eagle has notified us of their plans to drill six 10,000’ horizontal wells in Reagan County with spud dates in July and production start expected in December 2023. These six wells will be drilled on an acreage block that is an extension to Double Eagle’s Hughes Alpine development described above and where the Company holds leasehold acreage giving us the right to participate for approximately 6.5% interest in these two-mile-long horizontals. Our share of the investment in these will be approximately $4 million.

Reserves

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, 2022. 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 district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight 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 degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

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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)
2020		2,684		2,258		13,633		7,214		1,784		787		3,897		3,221		4,468		3,045		17,530		10,435
2021		5,386		2,882		23,902		12,252		—		—		—		—		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

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

In 2020, in West Texas we participated in the drilling of seven wells: one with Pioneer Natural Resources for 8.6% interest which was brought into production in July of 2020, and six wells with Apache on our Kashmir tract with an average 47.5% interest that were drilled but not completed at year-end and therefore classified as Proved Undeveloped in the year-end 2020 reserve report. The Company invested approximately $8.0 million in these seven wells in 2020. Also in 2020, reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest. In our Gulf Coast Region, in 2020, we successfully recompleted one operated well in the Segno field of Polk County, Texas with a 72.5% interest.

At December 31, 2020, in total, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, 10 of which were drilled but not completed by year-end 2020, and three that were not drilled until 2021. The three new horizontals along with the six uncompleted wells at year-end were brought online in late September and early October of 2021. These successful new wells are on our Kashmir tract in Upton County, Texas operated by Apache Corporation. These nine PUD wells at year-end 2020 accounted for 3,127 Mboe of the total undeveloped. The four other PUD wells, drilled but not completed at year-end 2020, are located in Grady County, Oklahoma, and accounted for 95 Mboe of the total undeveloped reserves.

In 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 Mid-Continent 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 Mid-Continent, Inc., 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 interests. 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 horizontal wells located in West Texas operated by three different operators. In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital investment of $12.1 million. In Reagan County, we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million. Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million. All twenty of these West Texas wells are either producing or are in the process of being completed. All 10 of the wells drilled by Hibernia Energy III in the first quarter were put on production in late April 2023. The five active horizontal wells operated by Double Eagle are in the process of being completed and slated to be on production in June of 2023. The remaining five wells with ConocoPhillips are expected to start completion in June and be on production in August of 2023.

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In January of 2023, the Company joined Ovintiv USA, Inc. in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000. Production is expected to begin in June of 2023. In addition, in March of 2023, Apache Corporation spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16.1 million. We anticipate completion of these two 15,000’ long horizontals in Upton County in May and initial production to occur in the third quarter of 2023.

At December 31, 2022, the Company had 6,366 Mboe of proved undeveloped reserves attributable to the 25 horizontal wells described above. In total, the Company expects to invest $78 million in these 25 horizontal wells, all of which, as of April 30, 2023, have been drilled and are either producing or in the process of being completed with production to begin by the end of the second quarter or early in the third quarter of 2023. Additional anticipated development mentioned in this report is not included in the 2022 year-end reserve report.

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, 2022, 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
2020	$	43,886	$	34,717	$	37,346	$	21,823	$	81,232	$	56,539	$	14,920	$	41,619
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

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 $6.358 per MMBtu in 2022 as compared to $3.598 per MMBtu in 2021, and $1.985 per MMBtu in 2020. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first of the month average spot price, were $93.67 per barrel in 2022 as compared to $66.56 per barrel in 2021, and $39.57 per barrel in 2020. Since January 1, 2022, 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.

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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. In 2023, we will continue our focus on preserving financial flexibility and ample 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.

We are actively developing our leasehold acreage in West Texas and in Oklahoma and on track to drill and complete approximately 40 wells in 2023. The following is a description of recent, current, and expected near-term drilling activities.

In 2021, The Company participated for 47.5% interest with Apache Corporation in the drilling of nine two-mile-long horizontal wells in Upton County, Texas, and with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma. Twelve of these horizontal wells were completed and placed into production in the fourth quarter of 2021. One of the Ovintiv wells, however, had a casing leak issue and has been temporarily abandoned. The Company invested approximately $32 million in these thirteen wells.

In the first three quarters of 2022, the Company participated in eight horizontal wells. Four of these wells are located in Irion County, West Texas, operated by SEM Operating Company, and four are located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc. Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022.

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators. In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital investment of $12.1 million. In Reagan County, we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million. Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million. All twenty of these West Texas wells have been drilled and are either producing or in the process of being completed. All 10 of the wells operated by Hibernia Energy III were put on production in late April 2023. The five wells operated by Double Eagle are expected to be on production in June of 2023. The remaining five wells with ConocoPhillips are expected to start completion in June and be on production in August of 2023.

In January of 2023, the Company joined Ovintiv USA, Inc. in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000. Production is expected to begin in June of 2023. In addition, in March of 2023, Apache Corporation spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16.1 million. We anticipate completion of these two 15,000’ long horizontals in Upton County in May and initial production to occur in the third quarter of 2023.

In total, the Company expects to invest $78 million in these 25 horizontal wells. In December 2022, we prepaid $32 million toward drilling costs, and the remaining $46 million in estimated drilling and completion expenses will be incurred in 2023. All 25 wells have been drilled as of May 1, 2023. Ten wells were put into production in late April, eight more are expected to be on-line in June of 2023 and the remaining seven wells are expected to be on production in June or early in the third quarter of 2023.

We anticipate that success from the 22 horizontals in West Texas described above will lead to additional near-term horizontal drilling covering five leasehold blocks in three counties of West Texas: 26 additional 10,000’ long horizontals in Reagan County from Hibernia, Double Eagle, and BTA Oil Producers (or its successor in the South Stiles Project), ten additional 12,500’ long horizontals in Martin County by ConocoPhillips, and six additional 15,000’ long horizontals in Upton County by Apache. Based on the success of their recent 10 wells in Reagan County, Texas, Hibernia has indicated their intent to drill 16 additional 10,000’ long horizontal wells this year with spud dates to occur late in the third quarter and production to begin in the first quarter of 2024. Our interest in these wells will be from 37.5% to 50% with an average of 41.18% and our investment will be approximately $75 million.    In addition, Double Eagle has notified us of their plans to drill six 10,000’ horizontal wells in Reagan County with spud dates in July and production start expected in December 2023. These six wells will be drilled on an acreage block that is an extension to Double Eagle’s Hughes Alpine development described above and where the Company has leasehold acreage giving us the right to participate for approximately 6.5% interest in these two-mile-long horizontals. Our share of the investment in these wells will be approximately $4 million.

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The upcoming six wells to be drilled by Double Eagle, along with the 16 wells planned by Hibernia and the additional 26 drilling proposals we anticipate in the near future, will target pay intervals of the Wolfcamp and Spraberry formations and will require an estimated $200 million in net capital investment through 2024. We have also identified 27 horizontal locations that would be a natural progression of development for three of these project areas in Upton and Reagan counties. These 27 wells are anticipated to be drilled in the 2025-2026 timeframe and would require net investment of approximately $100 million. In total, with the $78 million current investment in 22 wells, the $200 million near-term investment in 48 wells in Upton and Reagan counties, $100 million in 27 subsequent drill sites, and additional drilling not yet scheduled, we are expecting to invest approximately $400 million in horizontal development over the next several years.

In the Permian Basin of West Texas and eastern New Mexico, we maintain an acreage position of approximately 16,139 gross (9,569 net) acres, 96.5% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current West Texas horizontal drilling activities are focused. We believe this acreage has the resource potential to support the drilling of as many as 190 future horizontal wells following the active 22 and anticipated 42 horizontal wells described above.

In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,113 net leasehold acres in the Scoop/Stack Play. We are currently participating with Ovintiv in three 3-mile-long horizontals in Canadian County with 1.95% Of our 4,113 net leasehold acres, we believe 2,355 net acres hold significant additional resource potential that could support the drilling of as many as 46 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. In the near term, we anticipate nine new drilling proposals to be received with an estimated net expense of $5.2 million covering 338 net leasehold acres. 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.

RESULTS OF OPERATIONS

We reported net income of $1.4 million, $0.75 per share, for the three months ended March 2023 compared with $11.1 million, $5.62 per share, for the same period of 2022. The current year net income reflects changes in oil, gas and NGLs sales related to changes in production combined with lower commodity prices offset by net gains on derivative contracts. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales decreased 44.8% to $18.7 million for the three months ended March 2023 from $33.9 million in the same period of 2022. Sales vary due to changes in volumes of production sold and realized commodity prices. Our oil production decreased reflecting the natural decline in production from our West Texas wells added in the fourth quarter of 2021 and our Oklahoma wells which were placed in production in January 2022. The changes in volumes and prices are presented in the table below. The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended March 31, 2023, and 2022 (excluding realized gains and losses from derivatives).

			Three Months Ended March 31,
	2023		2022		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		193,351		273,000		(79,649	)		(29.18	)%
Average Price Received	$	75.40	$	96.36	$	(20.96	)		(21.75	)%
Oil Revenue (In 000’s)	$	14,578	$	26,305	$	(11,727	)		(44.58	)%
Mcf of Gas Sold		801,084		777,000		24,084			3.10	%
Average Price Received	$	2.19	$	4.82	$	(2.63	)		(54.56	)%
Gas Revenue (In 000’s)	$	1,752	$	3,746	$	(1,994	)		(53.23	)%
Barrels of Natural Gas Liquids Sold		105,825		104,000		1,825			1.75	%
Average Price Received	$	22.62	$	37.03	$	(14.41	)		(38.91	)%
Natural Gas Liquids Revenue (In 000’s)	$	2,394	$	3,851	$	(1,457	)		(37.83	)%
Total Oil & Gas Revenue (In 000’s)	$	18,724	$	33,902	$	(15,178	)		(44.77	)%

17

Gains or Losses on derivative instruments 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 condensed consolidated statements of operations. 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 three months ended March 31.

	2023			2022
Unrealized gain (loss) on natural gas derivative instruments	$	211		$	(1,948	)
Unrealized gain (loss) on crude oil derivative instruments		769			(5,191	)
Realized gain (loss) on natural gas derivative instruments		24			(620	)
Realized (loss) on crude oil derivative instruments		(590	)		(3,199	)
	$	414		$	(10,958	)

Average oil and gas prices received for the three months ended March 31, including the impact of derivatives were:

	2023		2022
Average sales prices per barrel of oil	$	76.32	$	84.52
Average sales price per MCF of natural gas	$	2.48	$	4.02

Lease operating expense decreased $0.7 million or 8.0% from $8.7 million for the first quarter 2022 to $8.0 million for the first quarter 2023. This decrease reflects the decreased production taxes related to the decreased oil, gas and NGL revenue, net of the additional operating expenses related to the wells added in 2022.

Field service income increased $0.5 million or 16.7% for the first quarter 2023 to $3.5 million from $3.0 million for the first quarter 2022. This increase is a combined result of increased utilization and rates charged to customers during the current quarter compared to the same quarter in 2022. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.

Field service expense increased $0.5 million or 18.5% to $3.2 million for the first quarter 2023 from $2.7 million for the first quarter 2022. Field service expenses primarily consist of wages and equipment operating expenses which have increased during the three months ended March 31, 2023 over the same period of 2022 related to increased utilization of the equipment during the current quarter compared to the same quarter in 2022.

Depreciation, depletion and amortization decreased $0.6 million or 8.6% from $7.0 million for the first quarter 2022 to $6.4 million for the first quarter 2023 reflecting the decreased production in the first quarter of 2023.

General and administrative expense decreased $3.6 million or 53.7% from $6.7 million for the three months ended March 31, 2022 to $3.1 million for the three months ended March 31, 2023. This decrease in 2023 is primarily due to decreased employee compensation and benefits.

Interest expense decreased $0.1 million or 33.3% from $0.3 million for the first quarter 2022 to $0.2 million for the first quarter 2023. This decrease reflects the decrease in current borrowings under our revolving credit agreement.

Income tax expense for the March 31, 2023 and 2022 quarters 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 2023, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2023 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.

Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage. Net cash provided by operating activities and proceeds from the sale of properties for the quarter ended March 31, 2023 was $30.3 million, compared to $23.3 million in the prior year.

18

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 required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. If the borrowing base utilization percentage is less than 15% of total available borrowings, the Company is not required to enter into any hedge agreements. The Company has no outstanding borrowings and all hedge agreements were settled or terminated prior to March 31, 2023. 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 $60 million. As of May 19, 2023, the Company has no outstanding borrowings under this line. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for June 2023. 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 quarter of 2023 was $2.75 million. The Company expects continued spending under the stock repurchase program in 2023.

19

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 three months of 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

20

PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

None.

Item 1A. RISK FACTORS

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

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no sales of equity securities by the Company during the period covered by this report. There was no purchase of equity securities by the Company during the period covered by this report.

2023 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		9,500	$	90.36		47,144
February		3,000	$	90.32		44,144
March		18,940	$	85.44		25,204
Total/Average		31,440	$	87.39

(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 and June 13, 2018, the Board of Directors of the Company approved an additional 500,000 and 200,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 3,700,000 shares have been authorized, to date, under this program. Through March 31, 2023, a total of 3,676,896 shares have been repurchased under this program for $85,229,534 at an average price of $23.18 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

21

Item 6. EXHIBITS

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

Exhibit     No.
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).
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 (Incorporated by reference to Exhibit 10.22.6.1 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2022).
14	PrimeEnergy Resources Corporation Code of Business Conduct and Ethics, as amended December 16, 2011 (Incorporated by reference to Exhibit 14 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2011).
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).
101.INS	Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)

22

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)

23

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)
May 22, 2023	/s/ Charles E. Drimal, Jr.
(Date)	Charles E. Drimal, Jr.
	President
	Principal Executive Officer
	/s/ Beverly A. Cummings
May 22, 2023	Beverly A. Cummings
	Executive Vice President
	Principal Financial Officer

24

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Charles E. Drimal, Jr., Chief Executive Officer of PrimeEnergy Resources Corporation, certify that:

1. I have reviewed this Form 10-Q for the quarter ended March 31, 2023 of PrimeEnergy Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 22, 2023

/s/ Charles E. Drimal, Jr.

Charles E. Drimal, Jr.

Chief Executive Officer

PrimeEnergy Resources Corporation

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Resources Corporation, certify that:

1. I have reviewed this Form 10-Q for the quarter ended March 31, 2023 of PrimeEnergy Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 22, 2023

/s/ Beverly A. Cummings

Beverly A. Cummings

Chief Financial Officer

PrimeEnergy Resources Corporation

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-Q for the period ending March 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles E. Drimal Jr., Chief Executive Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Charles E. Drimal, Jr.

Charles E. Drimal, Jr.

Chief Executive Officer

May 22, 2023

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-Q for the period ending March 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Beverly A. Cummings

Beverly A. Cummings

Chief Financial Officer

May 22, 2023

XML

Cover Page - shares	3 Months Ended
	Mar. 31, 2023	May 16, 2023
Cover [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2023
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1
Entity Registrant Name	PrimeEnergy Resources Corporation
Entity Central Index Key	0000056868
Current Fiscal Year End Date	--03-31
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Title of 12(b) Security	Common Stock
Trading Symbol	PNRG
Security Exchange Name	NASDAQ
Entity Common Stock, Shares Outstanding		1,850,500
Document Transition Report	false
Entity File Number	0-7406
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	9821 Katy Freeway
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77024
City Area Code	713
Local Phone Number	735-0000
Entity Tax Identification Number	84-0637348
Document Quarterly Report	true

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Current Assets
Cash and cash equivalents	$ 13,723	$ 26,543
Accounts receivable, net	11,151	12,147
Prepaid obligations	16,139	32,839
Due from related parties	373	388
Derivative asset	0	210
Other current assets	38	38
Total Current Assets	41,424	72,165
Property and Equipment
Oil and gas properties at cost	584,701	555,280
Less: Accumulated depletion and depreciation	(391,882)	(385,811)
Oil and gas properties, net	192,819	169,469
Field and office equipment at cost	27,086	27,246
Less: Accumulated depreciation	(22,940)	(22,728)
Field and office equipment, net	4,146	4,518
Total Property and Equipment, Net	196,965	173,987
Derivative asset long-term and other assets	951	985
Total Assets	239,340	247,137
Current Liabilities
Accounts payable	15,935	11,451
Accrued liabilities	26,135	25,750
Current portion of asset retirement and other long-term obligations	2,172	2,566
Derivative liability short-term	0	1,190
Total Current Liabilities	44,242	40,957
Long-Term Bank Debt	0	11,000
Asset Retirement Obligations	13,708	13,525
Deferred Income Taxes	40,387	39,968
Other Long-Term Obligations	1,988	1,334
Total Liabilities	100,325	106,784
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2023 and 2022: Authorized: 2,810,000 shares, outstanding 2023: 1,869,560; outstanding 2022: 1,901,000 shares	281	281
Paid-in capital	7,555	7,555
Retained earnings	178,976	177,566
Treasury stock, at cost; 2023: 940,440 shares; 2022: 909,000	(47,797)	(45,049)
Total Equity	139,015	140,353
Total Liabilities and Equity	$ 239,340	$ 247,137

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.10	$ 0.10
Common stock, shares authorized	2,810,000	2,810,000
Common stock, shares outstanding	1,869,560	1,901,000
Treasury stock, shares	940,440	909,000

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Revenues
Realized loss on derivative instruments, net	$ (566)	$ (3,819)
Unrealized gain (loss) on derivative instruments, net	980	(7,139)
Other income	38	29
Total Revenues	22,650	25,931
Costs and Expenses
Lease operating expense	7,974	8,719
Field service expense	3,167	2,720
Depreciation, depletion, amortization	6,422	7,008
Accretion of discount on asset retirement obligations	183	170
General and administrative expense	3,102	6,672
Total Costs and Expenses	20,848	25,289
Gain on Sale and Exchange of Assets	51	13,991
Income from Operations	1,853	14,633
Other Income (Expense)
Interest expense	(182)	(349)
Interest Income	114
Income Before Provision for Income Taxes	1,785	14,284
Provision for Income Taxes	375	3,142
Net Income	$ 1,410	$ 11,142
Basic Income Per Common Share	$ 0.75	$ 5.62
Diluted Income Per Common Share	$ 0.53	$ 4.07
Oil sales [Member]
Revenues
Oil, gas and service income	$ 14,578	$ 26,305
Natural gas sales [Member]
Revenues
Oil, gas and service income	1,752	3,746
Natural gas liquids sales [Member]
Revenues
Oil, gas and service income	2,394	3,851
Oil and gas service [Member]
Revenues
Oil, gas and service income	$ 3,474	$ 2,958

XML

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid in capital	Retained Earnings [Member]	Treasury Stock [Member]	Total Stockholders' Equity – PrimeEnergy [Member]	Shares Outstanding [Member]
Balance at Dec. 31, 2021		$ 281	$ 7,555	$ 128,902	$ (37,647)	$ 99,091
Balance, shares at Dec. 31, 2021							1,992,077
Repurchase shares of common stock					(833)	(833)
Repurchase shares of common stock, shares	(11,188)						(11,188)
Net Income	$ 11,142			11,142		11,142
Balance at Mar. 31, 2022		281	7,555	140,044	(38,480)	109,400
Balance, shares at Mar. 31, 2022							1,980,889
Balance at Dec. 31, 2022		281	7,555	177,566	(45,049)	140,353
Balance, shares at Dec. 31, 2022							1,901,000
Repurchase shares of common stock					(2,748)	(2,748)
Repurchase shares of common stock, shares	(31,440)						(31,440)
Net Income	$ 1,410			1,410		1,410
Balance at Mar. 31, 2023		$ 281	$ 7,555	$ 178,976	$ (47,797)	$ 139,015
Balance, shares at Mar. 31, 2023							1,869,560

XML

CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - shares	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Repurchase of common stock, shares	31,440	11,188

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Cash Flows from Operating Activities:
Net Income	$ 1,410	$ 11,142
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities	6,605	7,178
Gain on sale and exchange of assets	(51)	(13,991)
Unrealized (gain) loss on derivative instruments, net	(980)	7,139
Deferred income taxes	419	3,143
Changes in assets and liabilities:
Accounts receivable	996	(6,471)
Due from related parties	15	(52)
Prepaids obligations	16,700	565
Other long-term obligations	654	0
Accounts payable	4,484	1,814
Accrued liabilities	385	(1,112)
Net Cash Provided by Operating Activities	30,637	9,355
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense	(30,149)	(1,784)
Proceeds from sale of properties and equipment	440	13,991
Net Cash (Used in) Provided by Investing Activities	(29,709)	12,207
Cash Flows from Financing Activities:
Purchase of stock for treasury	(2,748)	(833)
Repayment of long-term bank debt and other long-term obligations	(11,000)	(27,000)
Net Cash (Used in) Financing Activities	(13,748)	(27,833)
Net (Decrease) in Cash and Cash Equivalents	(12,820)	(6,271)
Cash and Cash Equivalents at the Beginning of the Period	26,543	10,347
Cash and Cash Equivalents at the End of the Period	13,723	4,076
Supplemental Disclosures:
Interest paid	$ 167	$ 240

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Basis of Presentation

3 Months Ended

Mar. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

(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, 2022. 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 March 31, 2023, and December 31, 2022, the consolidated results of operations, cash flows and equity for the three months ended March 31, 2023, and 2022.

As of March 31, 2023, 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, 2022. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

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Acquisitions and Dispositions

3 Months Ended

Mar. 31, 2023

Business Combinations [Abstract]

Acquisitions and Dispositions

(2) Acquisitions and Dispositions

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 first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.0 million.

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Additional Balance Sheet Information

3 Months Ended

Mar. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Additional Balance Sheet Information

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)	March 31, 2023			December 31, 2022
Accounts Receivable:
Joint interest billing	$	1,821		$	1,806
Trade receivables		1,874			1,762
Oil and gas sales		7,698			8,894
Other		61			21
		11,454			12,483
Less: Allowance for doubtful accounts		(303	)		(336	)
Total	$	11,151		$	12,147
Accounts Payable:
Trade	$	10,146		$	5,142
Royalty and other owners		3,279			3,600
Partner advances		1,112			1,111
Other		1,398			1,598
Total	$	15,935		$	11,451
Accrued Liabilities:
Compensation and related expenses	$	4,665		$	9,743
Property costs		10,933			6,413
Taxes		9,333			9,352
Other		1,204			242
Total	$	26,135		$	25,750

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Long-Term Debt

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Long-Term Debt

(4) Long-Term Debt:

Bank Debt:

The Company maintains a revolving corporate credit facility (the “Credit Facility”) with a group of financial institutions with aggregate loan commitments of $300 million, subject to a borrowing base that is determined semi-annually, with a maturity date of June 1, 2026. As of December 31, 2022, the borrowing base was $75 million and the Company had $11 million outstanding borrowings under the Credit Facility.

The Credit Facility requires 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, and places restrictions on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements. As of March 31, 2023, the Company was in compliance with its debt covenants. Borrowings bear interest, at the option of the Company, based on a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) Adjusted Term SOFR (secured overnight financing rate as administered by the Federal Reserve Bank of New York) for a one-month tenor in effect on such day plus 1.00%, or a Term SOFR. Both options are subject to an additional margin, determined based upon the utilization of the borrowing base then in effect, ranging from 2.25% to 4.25% per annum. The Company also pays commitment fees on undrawn amounts under the Credit Facility of 0.50% per annum. Borrowings under the Credit Facility are secured by substantially all of the Company’s oil and gas properties.

Effective January 20, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and Prime 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.

As of March 31, 2023, the borrowing base was $60 million and the Company had no outstanding borrowings under the Credit Facility.

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Other Long-Term Obligations and Commitments

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Other Long-Term Obligations and Commitments

(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. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for office equipment is included in property and equipment, current portion of asset retirement and other long-term obligations this quarter. 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 7.82%. 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. Leases with an initial term of 12 months or less are not recorded on the balance sheet.

Operating lease costs for the three months ended March 31, 2023, and 2022 were $165 thousand and $142 thousand, respectively. Cash payments included in the operating lease cost for the three months ended March 31, 2023, and 2022 were $178 thousand and $150 thousand, respectively. The weighted average remaining operating lease terms as of March 31, 2023, and 2022 were 9.63 months and 12 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for payments of $561,000 in 2023, $275,000 in 2024, and $45,000 in 2025.

Rent expense for office space the quarter ended March 31, 2023 and 2022 was $141,000 and $177,000, respectively.

The payment schedule for the Company’s operating lease obligations as of March 31, 2023 is as follows:

(Thousands of dollars)	Operating Leases
2023	$	561
2024		275
2025		45
Total undiscounted lease payments	$	881
Less: Amount associated with discounting		(63	)
Total net operating lease liabilities	$	818
Less: Current portion included in Current portion of asset retirement and Other Long-Term Obligations		661
Non-Current portion included in Other Long-Term Obligations	$	157

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2023 is as follows:

(Thousands of dollars)	March 31, 2023
Asset retirement obligation at December 31, 2022	$	15,443
Liabilities settled		(407	)
Accretion of discount		183
Asset retirement obligation at March 31, 2023	$	15,219
Less current portion of asset retirement obligations		(1,511	)
Asset retirement obligations, long-term	$	13,708

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.

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Contingent Liabilities

3 Months Ended

Mar. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities

(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.

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Stock Options and Other Compensation

3 Months Ended

Mar. 31, 2023

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Options and Other Compensation

(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 March 31, 2023 and 2022, 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.

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Related Party Transactions

3 Months Ended

Mar. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

(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.

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Financial Instruments

3 Months Ended

Mar. 31, 2023

Fair Value Disclosures [Abstract]

Financial Instruments

(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 following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at March 31, 2023 and December 31, 2022:

March 31, 2023	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2023
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	—	$	—
Total assets	$	—	$	—	$	—	$	—

March 31, 2023	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at March 31, 2023
(Thousands of dollars)
Liabilities
Commodity derivative contracts	$	—	$	—	$	—		$	—
Total liabilities	$	—	$	—	$	—		$	—
December 31, 2022	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2022
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	210		$	210
Total assets	$	—	$	—	$	210		$	210
Liabilities
Commodity derivative contracts	$	—	$	—	$	(1,190	)	$	(1,190	)
Total liabilities	$	—	$	—	$	(1,190	)	$	(980	)

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 LIBOR 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 were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2023.

(Thousands of dollars)
Net Liabilities – December 31, 2022	$	(980	)
Total realized and unrealized gains (losses):
Included in earnings (a)		414
Purchases, sales, issuances and settlements		566
Net Liabilities — March 31, 2023	$	—

(a) Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on 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.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at March 31, 2023 and December 31, 2022:

			Fair Value
(Thousands of dollars)	Balance Sheet Location		March 31, 2023		December 31, 2022
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contract		Other current assets	$	—	$	162
Natural gas commodity contract		Other current assets		—		48
Total			$	—	$	210
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term	$	—	$	(931	)
Natural gas commodity contracts		Derivative liability short-term		—		(259	)
Crude oil commodity contracts		Derivative liability long-term		—		—
Natural gas commodity contracts		Derivative liability long-term		—		—
Total			$	—	$	(1,190	)
Total derivative instruments			$	—	$	(980	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the three months ended March 31, 2023 and 2022:

		Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2023			2022
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net		211			(1,948	)
Crude oil commodity contracts	Unrealized gain (loss) on derivative instruments, net		769			(5,191	)
Natural gas commodity contracts	Realized gain (loss) on derivative instruments, net		24			(620	)
Crude oil commodity contracts	Realized loss on derivative instruments, net		(590	)		(3,199	)
		$	414		$	(10,958	)

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Earnings per Share

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

Earnings per Share

(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:

	Quarter Ended March 31,
	2023						2022
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	1,410		1,888,895	$	0.75	$	11,142		1,980,878	$	5.62
Effect of dilutive securities:
Options				758,325						756,544
Diluted	$	1,410		2,647,220	$	0.53	$	11,142		2,737,422	$	4.07

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Additional Balance Sheet Information (Tables)

3 Months Ended

Mar. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Components of Balance Sheet Amounts

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)	March 31, 2023			December 31, 2022
Accounts Receivable:
Joint interest billing	$	1,821		$	1,806
Trade receivables		1,874			1,762
Oil and gas sales		7,698			8,894
Other		61			21
		11,454			12,483
Less: Allowance for doubtful accounts		(303	)		(336	)
Total	$	11,151		$	12,147
Accounts Payable:
Trade	$	10,146		$	5,142
Royalty and other owners		3,279			3,600
Partner advances		1,112			1,111
Other		1,398			1,598
Total	$	15,935		$	11,451
Accrued Liabilities:
Compensation and related expenses	$	4,665		$	9,743
Property costs		10,933			6,413
Taxes		9,333			9,352
Other		1,204			242
Total	$	26,135		$	25,750

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Other Long-Term Obligations and Commitments (Tables)

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Summary of Operating and Financing Lease Obligation

The payment schedule for the Company’s operating lease obligations as of March 31, 2023 is as follows:

(Thousands of dollars)	Operating Leases
2023	$	561
2024		275
2025		45
Total undiscounted lease payments	$	881
Less: Amount associated with discounting		(63	)
Total net operating lease liabilities	$	818
Less: Current portion included in Current portion of asset retirement and Other Long-Term Obligations		661
Non-Current portion included in Other Long-Term Obligations	$	157

Reconciliation of Liability for Plugging and Abandonment Costs

A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2023 is as follows:

(Thousands of dollars)	March 31, 2023
Asset retirement obligation at December 31, 2022	$	15,443
Liabilities settled		(407	)
Accretion of discount		183
Asset retirement obligation at March 31, 2023	$	15,219
Less current portion of asset retirement obligations		(1,511	)
Asset retirement obligations, long-term	$	13,708

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Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2023

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis

The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at March 31, 2023 and December 31, 2022:

March 31, 2023	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2023
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	—	$	—
Total assets	$	—	$	—	$	—	$	—

March 31, 2023	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at March 31, 2023
(Thousands of dollars)
Liabilities
Commodity derivative contracts	$	—	$	—	$	—		$	—
Total liabilities	$	—	$	—	$	—		$	—
December 31, 2022	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2022
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	210		$	210
Total assets	$	—	$	—	$	210		$	210
Liabilities
Commodity derivative contracts	$	—	$	—	$	(1,190	)	$	(1,190	)
Total liabilities	$	—	$	—	$	(1,190	)	$	(980	)

Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2023.

(Thousands of dollars)
Net Liabilities – December 31, 2022	$	(980	)
Total realized and unrealized gains (losses):
Included in earnings (a)		414
Purchases, sales, issuances and settlements		566
Net Liabilities — March 31, 2023	$	—

(a) Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments.

Effect of Derivative Instruments on Consolidated Balance Sheets

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at March 31, 2023 and December 31, 2022:

			Fair Value
(Thousands of dollars)	Balance Sheet Location		March 31, 2023		December 31, 2022
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contract		Other current assets	$	—	$	162
Natural gas commodity contract		Other current assets		—		48
Total			$	—	$	210
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term	$	—	$	(931	)
Natural gas commodity contracts		Derivative liability short-term		—		(259	)
Crude oil commodity contracts		Derivative liability long-term		—		—
Natural gas commodity contracts		Derivative liability long-term		—		—
Total			$	—	$	(1,190	)
Total derivative instruments			$	—	$	(980	)

Effect of Derivative Instruments on Consolidated Statements of Operations

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the three months ended March 31, 2023 and 2022:

		Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2023			2022
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net		211			(1,948	)
Crude oil commodity contracts	Unrealized gain (loss) on derivative instruments, net		769			(5,191	)
Natural gas commodity contracts	Realized gain (loss) on derivative instruments, net		24			(620	)
Crude oil commodity contracts	Realized loss on derivative instruments, net		(590	)		(3,199	)
		$	414		$	(10,958	)

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Earnings per Share (Tables)

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings (Loss) per Share

The following reconciles amounts reported in the consolidated financial statements:

	Quarter Ended March 31,
	2023						2022
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	1,410		1,888,895	$	0.75	$	11,142		1,980,878	$	5.62
Effect of dilutive securities:
Options				758,325						756,544
Diluted	$	1,410		2,647,220	$	0.53	$	11,142		2,737,422	$	4.07

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Acquisitions and Dispositions - Additional Information (Detail) - TEXAS	3 Months Ended
	Mar. 31, 2023 USD ($) a	Mar. 31, 2022 USD ($) a
Business Acquisition [Line Items]
Number of Acres Sold | a	7.8	1,809
Proceeds from Divestiture of Businesses	$ 436,050	$ 14,000,000
Gain (Loss) on Disposition of Business	$ 47,000

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Additional Balance Sheet Information - Components of Balance Sheet Amounts (Detail) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Accounts Receivable:
Joint interest billings	$ 1,821	$ 1,806
Trade receivables	1,874	1,762
Oil and gas sales	7,698	8,894
Other	61	21
Accounts Receivable, Gross	11,454	12,483
Less: Allowance for doubtful accounts	(303)	(336)
Total	11,151	12,147
Accounts Payable:
Trade	10,146	5,142
Royalty and other owners	3,279	3,600
Partner advances	1,112	1,111
Other	1,398	1,598
Total	15,935	11,451
Accrued Liabilities:
Compensation and related expenses	4,665	9,743
Property costs	10,933	6,413
Taxes	9,333	9,352
Other	1,204	242
Total	$ 26,135	$ 25,750

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands		3 Months Ended
	Jan. 20, 2023	Mar. 31, 2023	Dec. 31, 2022
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		4.25%
Maximum [Member] | 2022 Credit Agreement
Debt Instrument [Line Items]
Decrease in Borrowing Base	$ 75
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%
Minimum [Member] | 2022 Credit Agreement
Debt Instrument [Line Items]
Decrease in Borrowing Base	$ 60
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility borrowing capacity		$ 300,000
Line of credit facility, expiration date		Jun. 01, 2026
Long-term Line of Credit			$ 11,000
Outstanding borrowings		$ 0
Debt Instrument, Face Amount		$ 60	$ 75,000
Debt Instrument, Basis Spread on Variable Rate		0.50%
Fed Funds Effective Rate Overnight Index Swap Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%

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Other Long-Term Obligations and Commitments - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Weighted-average discount rate	7.82%
Operating lease weighted-average remaining lease term	9 months 19 days	12 months
Operating lease payments	$ 178,000	$ 150,000
Operating lease cost	$ 165,000	142,000
Lease period description	The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term.
Rent Expenses	$ 141,000	$ 177,000
Lease Payments Due Next year	561,000
Lease payments due next two years	275,000
Lease payments due next third years	$ 45,000

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Other Long-Term Obligations and Commitments - Summary of Operating and Financing Lease Obligation (Detail)	Mar. 31, 2023 USD ($)
2023	$ 561,000
2024	275,000
2025	45,000
Total undiscounted lease payments	881,000
Less: Amount associated with discounting	(63,000)
Total net operating lease liabilities	818,000
Less: Current portion included in Current portion of asset retirement and Other Long-Term Obligations	661,000
Non-Current portion included in Other Long-Term Obligations	$ 157,000
Operating Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Total net operating lease liabilities

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Other Long-Term Obligations and Commitments - Reconciliation of Liability for Plugging and Abandonment Costs (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Asset retirement obligation	$ 15,443
Liabilities settled	(407)
Accretion of discount	183	$ 170
Asset retirement obligation	15,219
Less: Current portion included in Current portion of asset retirement and other long-term obligations	(1,511)
Asset retirement obligations, long-term	$ 13,708		$ 13,525

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Stock Options and Other Compensation - Additional Information (Detail)	Mar. 31, 2023 $ / shares shares	Dec. 31, 2022 $ / shares shares	May 31, 1989 Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, shares | shares	767,500	767,500
Number of key executive officers to whom non-statutory stock options granted | Officers			4
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average exercise price | $ / shares	$ 1	$ 1
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average exercise price | $ / shares	$ 1.25	$ 1.25
Nonstatutory Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options exercisable, shares | shares	767,500	767,500

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Financial Instruments - Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Assets
Derivative assets	$ 0	$ 210
Liabilities
Derivative liabilities	0	(1,190)
Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	0	210
Liabilities
Derivative liabilities	0	(980)
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	0	210
Liabilities
Derivative liabilities	0	(1,190)
Significant Unobservable Inputs (Level 3) [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	0	210
Liabilities
Derivative liabilities	0	(1,190)
Significant Unobservable Inputs (Level 3) [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	0	210
Liabilities
Derivative liabilities	$ 0	$ (1,190)

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Financial Instruments - Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3 (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2023 USD ($)
Total realized and unrealized (gains) losses:
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Liabilities at beginning of period	$ (980)
Total realized and unrealized (gains) losses:
Included in earnings	414	[1]
Purchases, sales, issuances and settlements	566
Net Liabilities end of period	$ 0

[1] Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments.

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Financial Instruments - Effect of Derivative Instruments on Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Derivative assets	$ 0	$ 210
Derivative liabilities	0	(1,190)
Total derivative instruments	0	(980)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0	48
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Derivative liability short-term [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	(259)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Derivative liability Long Term [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	0
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0	162
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Derivative liability short-term [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	(931)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Derivative liability Long Term [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 0	$ 0

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Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/loss recognized in income	$ 414	$ (10,958)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Unrealized gain (loss) on derivative instruments, net
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/loss recognized in income	$ 211	$ (1,948)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Realized gain (loss) on derivative instruments, net
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/loss recognized in income	24	(620)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Unrealized gain (loss) on derivative instruments, net
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/loss recognized in income	769	(5,191)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Realized loss on derivative instruments, net
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/loss recognized in income	$ (590)	$ (3,199)

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Earnings per Share - Computation of Basic and Diluted Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Earnings Per Share [Abstract]
Net Income, Basic	$ 1,410	$ 11,142
Net Income, Diluted	$ 1,410	$ 11,142
Weighted Average Number of Shares Outstanding, Basic	1,888,895	1,980,878
Weighted Average Number of Shares Outstanding, Options	758,325	756,544
Weighted Average Number of Shares Outstanding, Diluted	2,647,220	2,737,422
Per Share Amount, Basic	$ 0.75	$ 5.62
Per Share Amount, Diluted	$ 0.53	$ 4.07