UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM

10-Q

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

For the Quarterly Period Ended September 30, ~~2022~~2023

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

For the Transition Period From

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 November ~~18, 2022~~13, 2023 was: Common Stock, $0.10 par value ~~1,920,500~~1,820,576 shares.

PrimeEnergy Resources Corporation

Index to Form 10-Q

September 30, ~~2022~~2023


	Page
Definitions of Certain Terms and Conventions Used Herein		1
Cautionary Statement Concerning Forward-Looking Statements		3
Part I—Financial Information		4
Item 1. Financial Statements		4
~~Condensed~~ Consolidated Balance Sheets ~~– September~~–September 30, ~~2022~~2023 and December 31, ~~2021~~2022		34
~~Condensed~~ Consolidated Statements of Operations – For the three and nine months ended September 30, ~~2022~~2023 and ~~2021~~		4
~~Condensed Consolidated Statements of Equity – For the nine months ended September 30,~~ 2022 ~~and 2021~~		5
~~Condensed~~ Consolidated Statements of Equity – For the three and nine months ended September 30, 2023 and 2022		6
Consolidated Statements of Cash Flows – For the nine months ended September 30, ~~2022~~2023 and ~~2021~~2022		67
Notes to ~~Condensed~~ Consolidated Financial Statements – September 30, ~~2022~~2023		~~7-12~~8-13
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		1314-22
Item 3. Quantitative and Qualitative Disclosures About Market Risk		22
Item 4. Controls and Procedures		22

Part ~~II—~~II - Other Information		23

Item 1. Legal Proceedings		23

Item 1A. Risk Factors		23

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		23

Item 3. Defaults Upon Senior Securities		23

Item 4. Reserved		23

Item 5. Other Information		23

Item 6. Exhibits		24

Signatures		25

Definitions of Certain Terms and Conventions Used Herein

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

Measurements.

•

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

•

“BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid.

•

“BOEPD” means BOE per day.

•

“Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

•

“MBbl” means one thousand Bbls.

•

“MBOE” means one thousand BOEs.

•

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

•

“MMcf” means one million cubic feet.

Indices.

•

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

•

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

•

“WTI” means West Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil used as a benchmark in oil pricing. General terms and conventions.

•

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

•

“ESG” means environmental, social and governance.

•

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

•

“GHG” means greenhouse gases.

•

“LNG” means liquefied natural gas.

•

“NGLs” means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the gas stream; such liquids include ethane, propane, isobutane, normal butane and natural gasoline.

•

“NYMEX” means the New York Mercantile Exchange.

•

“OPEC” means the Organization of Petroleum Exporting Countries.

•

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

•

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

•

“Proved reserves” means those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

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

(ii)

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

(iii)

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

(iv)

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

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

•

“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)

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

(ii)

Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii)

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

•

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

•

“Standardized Measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a 10 percent discount rate.

•

“U.S.” means United States.

•

With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Company’s working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.

•

“WASP” means weighted average sales price.

All currency amounts are expressed in U.S. dollars.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This information in this Quarterly Report on Form 10-Q (this “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “models,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to the Company are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on the Company’s current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it.

These risks and uncertainties include, among other things, volatility of commodity prices; product supply and demand; the impact of armed conflict (including the war in Ukraine) and related political instability on economic activity and oil and gas supply and demand; competition; the ability to obtain drilling, environmental and other permits and the timing thereof; the effect of future regulatory or legislative actions on PrimeEnergy or the industry in which it operates, including potential changes to tax laws; the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms; potential liability resulting from pending or future litigation; the costs, including the potential impact of cost increases due to inflation and supply chain disruptions, and results of development and operating activities; the impact of a widespread outbreak of an illness, such as the COVID19 pandemic, on global and U.S. economic activity, oil and gas demand, and global and U.S. supply chains; the risk of new restrictions with respect to development activities, including potential changes to regulations resulting in limitations on the Company’s ability to dispose of produced water; availability of equipment, services, resources and personnel required to perform the Company’s development and operating activities; access to and availability of transportation, processing, fractionation, refining, storage and export facilities; PrimeEnergy’s ability to replace reserves, implement its business plans or complete its development activities as scheduled; the Company’s ability to achieve its emissions reductions, flaring and other ESG goals; access to and cost of capital; the financial strength of (i) counterparties to PrimeEnergy’s credit facility and derivative contracts, (ii) issuers of PrimeEnergy’s investment securities and (iii) purchasers of PrimeEnergy’s oil, NGL and gas production and downstream sales of purchased commodities; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying forecasts, including forecasts of production, operating cash flow, well costs, capital expenditures, rates of return, expenses, and cash flow from downstream purchases and sales of oil and gas, net of firm transportation commitments; tax rates; quality of technical data; environmental and weather risks, including the possible impacts of climate change on the Company’s operations and demand for its products; cybersecurity risks; the risks associated with the ownership and operation of the Company’s water services business and acts of war or terrorism. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it.

Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk” and “Part II, Item 1A. Risk Factors” in this Report and “Part I, Item 1. Business — Competition,” “Part I, Item 1. Business —Regulation,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 for a description of various factors that could materially affect the ability of to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. PrimeEnergy undertakes no duty to publicly update these statements except as required by law.

PART I—FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

~~ONDENSED~~

ONSOLIDATED

ALANCE

HEETS

~~– Unaudited~~

(in Thousands, ~~of dollars)~~

except share data)

September 30,

2022

December 31,

2021

ASSETS

Current Assets
Cash and cash equivalents    $ 24,059 $ 10,347
Accounts receivable, net    16,943 14,208
Prepaid obligations    783 733
Other current assets    348 40

Total Current Assets    42,133 25,328
Property and Equipment
Oil and gas properties at cost    545,345 539,484
Less: Accumulated depletion and depreciation    (380,287 ) (359,742 )

   165,058 179,742

Field and office equipment at cost    28,013 27,080
Less: Accumulated depreciation    (23,041 ) (22,159 )

   4,972 4,921

Total Property and Equipment, Net    170,030 184,663
Derivative asset long-term and other assets    736 923

Total Assets    $ 212,899 $ 210,914

LIABILITIES AND EQUITY

Current Liabilities
Accounts payable    $ 6,168 $ 7,282
Accrued liabilities    10,526 7,821
Due to related parties    113 52
Current portion of asset retirement and other long-term obligations    1,438 1,630
Derivative liability short-term    3,975 4,935

Total Current Liabilities    22,220 21,720
Long-Term Bank Debt    —   36,000
Asset Retirement Obligations    12,460 13,222
Derivative Liability Long-Term    —   650
Deferred Income Taxes    47,518 38,743
Other Long-Term Obligations    1,323 1,488

Total Liabilities    83,521 111,823
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2022 and 2021: Authorized: 2,810,000 shares, outstanding 2022: 1,930,700 shares; outstanding 2021: 1,992,077 shares.    281 281
Additional
paid-in
capital
   7,555 7,555
Retained earnings    164,181 128,902
Treasury stock, at cost; 2022: 879,300 shares; 2021: 817,923

shares
   (42,639 ) (37,647 )

Total Equity    129,378 99,091

Total Liabilities and Equity    $ 212,899 $ 210,914


	September 30, 2023 (Unaudited)			December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	19,790		$	26,543
Accounts receivable, net		17,372			12,147
Prepaid obligations		413			32,839
Due from related parties		—			388
Derivative asset		—			210
Other current assets		38			38

Total current assets		37,613			72,165
Properties and equipment:
Proved oil and gas properties, using the successful efforts method of accounting		610,655			555,280
Other property		27,004			27,246
Accumulated depletion and depreciation		(422,558	)		(408,539	)

Total properties, net		215,101			173,987
Right-of-use assets		458			852
Other assets		403			133

Total Assets	$	253,575		$	247,137

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	11,900		$	11,451
Accrued liabilities		28,450			25,750
Current portion of asset retirement and other long-term obligations		936			2,566
Due to related parties		398			—
Derivative liability		—			1,190

Total current liabilities		41,684			40,957
Long-term bank debt		—			11,000
Asset retirement obligations		11,567			13,525
Deferred income taxes		43,288			39,968
Other long-term obligations		1,035			1,334

Total Liabilities		97,574			106,784
COMMITMENTS AND CONTINGENCIES
Equity:
Common stock, $.10 par value; 2,810,000 shares authorized, 1,828,500 and 1,901,000 shares outstanding as of September 30, 2023 and December 31, 2022 respectively		281			281
Additional paid in capital		7,555			7,555
Retained earnings		199,786			177,566
Treasury stock, at cost; 981,500 and 909,000 shares as of September 30, 2023 and December 31, 2022, respectively		(51,621	)		(45,049	)

Total Equity		156,001			140,353

Total Liabilities and Equity	$	253,575		$	247,137

The financial information included as of September 30, 2023 and 2022 has been prepared by management without audit by independent registered public accountants.

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

consolidated financial statements

Table of Contents

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 nine months ended September 30, ~~2022.~~2023.


(Thousands of dollars)
Net Liabilities – December 31, 2021	$	(5,585	)
Total realized and unrealized (gains) losses:
Net Liabilities – December 31, 2022				$	(980	)
Total realized and unrealized gains (losses):
Included in earnings (a)		(12,074	)		414
Purchases, sales, issuances and settlements		13,992			566

Net Liabilities - September 30, 2022	$	(3,667	)
Net Liabilities — September 30, 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.

~~Table of Contents~~

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 September 30, ~~2022~~2023 and December 31, ~~2021:~~ 2022:


		Fair Value								Fair Value
(Thousands of dollars)	Balance Sheet Location	September 30, 2022			December 31, 2021			Balance Sheet Location		September 30, 2023		December 31, 2022
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative asset short-term	$	308		$	—
Crude oil commodity contract									Derivative asset	$	—	$	162
Natural gas commodity contract									Derivative asset		—		48

Total		$	308		$	—				$	—	$	210

Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative liability short-term	$	(2,072	)	$	(3,992	)		Derivative liability	$	—	$	(931	)
Natural gas commodity contracts	Derivative liability short-term		(1,903	)		(943	)		Derivative liability		—		(259	)
Crude oil commodity contracts	Derivative liability long-term		—			(490	)
Natural gas commodity contracts	Derivative liability long-term		—			(160	)

Total										$	—	$	(1,190	)

Total derivative instruments		$	(3,975	)	$	(5,585	)			$	—	$	(980	)

Total derivative instruments		$	(3,667	)	$	(5,585	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine months ended September 30, ~~2022~~2023 and ~~2021:~~ 2022:


		Amount of gain/loss recognized in income								Amount of gain (loss) recognized in in o me
(Thousands of dollars)	Location of gain/loss recognized in income	2022			2021			Location of gain/loss recognized in income		2023			2022
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized (loss) on derivative instruments, net	$	(800	)	$	(2,418	)		Unrealized gain (loss) on derivative instruments, net		211			(800	)
Crude oil commodity contracts	Unrealized gain (loss) on derivative instruments, net		2,718			(4,744	)		Unrealized gain on derivative instruments, net		769			2,718
Natural gas commodity contracts	Realized (loss) on derivative instruments, net		(3,603	)		(1,009	)		Realized gain (loss) on derivative instruments, net		24			(3,603	)
Crude oil commodity contracts	Realized (loss) on derivative instruments, net		(10,389	)		(1,887	)		Realized loss on derivative instruments, net		(590	)		(10,389	)

		$	(12,074	)	$	(10,058	)			$	414		$	(12,074	)

1112

Table of Contents

(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 financial statements:

Nine Months Ended September 30,


2022

2021


Net Income
(In 000’s)

Weighted

Average

Number of

Shares

Outstanding

Per

Share

Amount

Net

Loss

(In 000’s)

Weighted

Average

Number of

Shares

Outstanding

Per

Share

Amount

Basic    $ 35,279    1,965,334    $ 17.95    $ (5,021 ) 1,994,177    $ (2.52 )
Effect of dilutive securities:
Options (a)    —      757,218    —

Diluted    $ 35,279    2,722,522    $ 12.96    $ (5,021 ) 1,994,177    $ (2.52 )

Three Months Ended September 30,


2022

2021


Net Income

(In 000’s)

Weighted

Average

Number of

Shares

Outstanding

Per

Share

Amount

Net

Loss

(In 000’s)

Weighted

Average

Number of

Shares

Outstanding

Per

Share

Amount

Basic    $ 13,154    1,937,091    $ 6.79    $ (1,163 ) 1,994,177    $ (0.58 )
Effect of dilutive securities:
Options (a)    —      757,815    —      —   —      —

Diluted    $ 13,154    2,694,906    $ 4.88    $ (1,163 ) 1,994,177    $ (0.58 )

~~(a)~~

~~The effect of the 767,500 outstanding stock options is antidilutive for the nine and three months ended September 30, 2021 due to net loss for these periods.~~


	Nine Months Ended September 30,
	2023						2022
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	22,220		1,859,084	$	11.95	$	35,279		1,965,334	$	17.95
Effect of dilutive securities:
Options (a)		—		758,674				—		757,218		—

Diluted	$	22,220		2,617,758	$	8.49	$	35,279		2,722,522	$	12.96


	Three Months Ended September 30,
	2023						2022
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	10,720		1,834,709	$	5.84	$	13,154		1,937,091	$	6.79
Effect of dilutive securities:
Options (a)		—		759,214				—		757,815		—

Diluted	$	10,720		2,593,924	$	4.13	$	13,154		2,694,906	$	4.88

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. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia. We are currently not receiving revenue from this asset, as development has not begun. In addition, we own well-servicing equipment and, through a wholly owned offshore company, a ~~60-mile-long~~ ~~pipeline offshore on the shallow shelf of Texas not currently in use. 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.~~ 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~~more recently developed horizontal properties with relatively high flow rates. The Company also owns 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. In Oklahoma, we own 649 acres of land with an estimated value of approximately $848,000, however, in November of this year have agreed to sell 136 acres for $306,000. Also, in Prattville, Alabama, we hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres. There is currently no debt on the shopping center and ~~exploration potential.~~it has approximately $500,000 of working capital on its balance sheet. We believe our ~~balanced~~ portfolio of oil and gas 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 ~~our~~ operations, our credit facility, and existing cash on our balance sheet.

In addition to developing our oil and natural gas reserves, we continue to actively pursue the acquisition of producing properties. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition, ~~and for~~ exploration and ~~development operations in areas in which we own interests.~~development. 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 through consistent growth and development of our oil and gas reserve base on a cost-effective basis.~~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. WeOn occasion, we will use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of ~~any~~ 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. ~~Since~~When used, our derivative contracts are accounted for under mark-to-market accounting and we can expect ~~continued~~ volatility in gains and losses on~~mark-to-market~~ ~~derivative~~ contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. Our ~~existing~~most recent derivative instruments ~~expire~~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~~most recent contracts ~~are set to expire~~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 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 ~~NGL’s are higher than in the recent past, however, prices~~NGLs may be volatile, ~~and, consequently,~~therefore, 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.

~~We are the operator~~The Company is actively developing non-producing reserves of ~~the majority of our developed~~its leasehold acreage positions in Texas and ~~undeveloped acreage which is nearly all held by production.~~Oklahoma. In the Permian Basin of West Texas, ~~and eastern New Mexico~~ the Company maintains an acreage position of approximately ~~16,960 gross (10,640 net)~~9,266 net acres, ~~96.5%~~97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. In addition to the recent 22 horizontal wells completed so far in 2023 in West Texas, ~~horizontal drilling activities are focused. We~~we believe this acreage has significant resource potential in the Spraberry, Jo Mill, and Wolfcamp ~~intervals~~reservoirs 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 47,120 gross (10,300 net) acres. Our Oklahoma~~our horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin ~~counties. We believe~~counties where we have approximately ~~5,800~~4,113 net acres ~~in these counties hold significant~~with additional resource potential that could support the drilling of as many as 5043 new horizontal wells based on an estimate of four wells per ~~multi-section drilling unit,~~section: two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in such future development, our share of ~~these future~~ capital expenditures would be approximately ~~$34.6~~$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, ~~2021.~~2022.


Proved Reserves as of December 31, 2021 (MBoe)	Gulf Coast		Mid- Continent		West Texas		Other		Total
											Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves as of December 31, 2022 (MBoe)
Developed		906		2,383		8,957		6		12,252		790		2,549		7,001		13		10,353
Undeveloped Total		—		—		—		—		—
Undeveloped												—		110		6,256		—		6,366
Total												790		2,659		13,257		13		16,719
Average Net Daily Production (Boe per day)		336		747		2,878		3		3,964		227		897		3,257		4		4,385
Gross Productive Wells (Working Interest and ORRI Wells)		207		549		576		200		1,532		150		508		557		151		1,373
Gross Productive Wells (Working Interest Only)		189		400		530		88		1,207		132		383		511		82		1,108
Net Productive Wells (Working Interest Only)		105		189		263		6		564		69		169		254		6		498
Gross Operated Productive Wells		137		195		321		—		653		89		176		310		—		575
Gross Operated Water Disposal, Injection and Supply wells		7		44		6		—		57		7		40		6		—		53

In ~~several of~~ our West Texas and Gulf Coast producing regions we have field service groups tothat service our operated wells and ~~locations as well as~~provide well-site services to third-party operators. These services ~~consist of well service support, site preparation and construction services for drilling and workover operations. Our operations~~ are performed primarily utilizing workover or swab rigs, water transport trucks, hot-oil trucks, and saltwater disposal facilities ~~various land excavating equipment and trucks~~that we own and that are operated by our field employees.

Gulf Coast Region

Our production activities in the Gulf Coast region are ~~primarily production and development of our existing operated properties~~ concentrated in east and 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~~5,000 to ~~12,500~~11,000 feet. ~~As of~~On December 31, ~~2021,~~2022, we had 207 producing wells (105 net) in the Gulf Coast region, of which 137 wells are operated by us. The Average net daily production in our Gulf Coast Region in 2021 was 336 Boe. At December 31, 2021, we had 906790 MBoe of proved reserves in the Gulf Coast region, which represented 7%4.7% of our total proved reserves. As of that date, we had 150 producing wells (69 net) in the Gulf Coast region. Focus during the past year has been on the plug and abandonment of non-performing assets and we currently operate 29 wells in the region and have a working interest in an additional 43 non-operated wells. We maintain an acreage position of over ~~10,700~~8,707 gross ~~(3,215~~(3,782 net) acres in this region, primarily in ~~Dimmit and~~ Polk ~~counties.~~County. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, ~~twenty-three~~ water transport trucks, two commercial saltwater disposal wells, ~~and several~~hot oil trucks, and ~~excavating~~plugging 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. The Company also owns, through its wholly-owned offshore company, a ~~60-mile-long~~ ~~pipeline on the shallow shelf of Texas that is currently idle but may someday have value.~~ As of September 30, ~~2022,~~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, ~~2021,~~2022, we had ~~549~~508 producing wells ~~(189~~(169 net) in the Mid-Continent area, of which ~~195~~176 wells are operated by us. Principal producing intervals are in the ~~Roberson,~~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~~The average net daily production in our Mid-Continent Region in ~~2021~~2022 was ~~747~~897 Boe. On December 31, ~~2021,~~2022, we had ~~2,383~~2,659 MBoe of proved reserves in ~~the~~ ~~Mid-Continent~~ ~~area,~~this region, representing ~~20%~~16% of our total proved reserves. We currently maintain an acreage position of approximately ~~47,120~~46,960 gross ~~(10,300~~(10,137 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 ~~interests~~interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily ~~targets~~targeting reservoirs of the Mississippian and Woodford formations. On July 1, 2023, we divested of 38 marginally productive operated wells and one well on September 1, 2023 located in various counties of Oklahoma reducing our future plugging liability without a significant change in value of our producing reserves.

~~In the first half of 2022,~~Year-to-date, in the Mid-Continent region, the Company has participated with ~~9.38%~~1.96% interest in the drilling and completion of ~~four~~three 3-mile-long horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc. All ~~four~~three wells ~~have been completed and are online as~~were brought on production in June of ~~August 1st.~~this year. The ~~resulting production is an addition to our 2021~~expected reserves of these three wells were included in the 2022 year-end reserve report as proved ~~producing reserve base.~~undeveloped. The Company ~~divested of 354~~ ~~non-strategic~~ ~~acres~~has added additional proved-producing reserves through various over-riding royalty interests in ~~Canadian County,~~ ~~year-to-date,~~ ~~with proceeds of $1.269 million.~~12 horizontal wells, totaling 5.78% net revenue interest.

West Texas Region

Our West Texas activities are concentrated in the ~~Spraberry and Wolfcamp shale plays~~Permian Basin where much of the ~~Permian Basin encompassing eight counties in West Texas.~~United States’ oil reserves are produced from the prolific Wolfcamp and Spraberry reservoirs. The oil ~~produced from these shales~~ is West Texas Intermediate Sweet and the ~~gas is primarily~~produced casing-head gas ~~with an average energy~~has a high BTU content making it the primary source of ~~1,400 Btu.~~our natural gas liquids. The ~~horizontal target~~oil and gas are primarily from five producing intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ~~range~~ranging from ~~7,600~~6,700 feet to ~~12,500~~11,300 feet. This region is managed from our office in Midland, Texas.

As of December 31, ~~2021,~~2022, we had ~~576~~557 wells ~~(263~~(254 net) in the West Texas area, of which ~~321~~310 wells are operated by us. The average net daily production in Our West Texas Region ~~in 2021~~at year-end 2022 was ~~2,878~~3,257 Boe. OnAs of December 31, ~~2021,~~2022, we had ~~8,957~~13,256 MBoe of proved reserves in the West Texas area, or ~~73%~~79.3 % of our total proved reserves. We maintain an acreage position of approximately ~~16,960~~16,171 gross ~~(10,640~~(9,266 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 additional horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp pay intervals. We operate a field service group in this region utilizing nine workover rigs, ~~four~~three hot oiler trucks, and one kill ~~truck, and two roustabout trucks.~~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 ~~for~~in our own operated wells and locations.

In the first ~~half~~three quarters of ~~2022,~~2023, the Company ~~participated with 10.3% interest in the drilling of four~~ ~~1.5-mile-long~~has added 22 completed horizontal wells to its West Texas proved-producing portfolio through our participation in ~~Irion~~15 wells in Reagan County, ~~Texas~~five in Martin County, and two in Upton County. Ten of the 15 wells in Reagan County are operated by ~~SEM~~Civitas Resources (formerly Hibernia Energy III, LLC), located on our Brynn Tract, and five are operated by DE IV Operating, LLC (Double Eagle), located on our Prime East Tract. The five wells in Martin County are operated by ConocoPhillips on our Schenecker A Tract, and the two in Upton County, operated by Apache Corporation, are our Mt. Moran wells. The Company ~~LLC. All four wells have been drilled~~has invested approximately $78 million in these 22 horizontals and ~~completed and began production in early August.~~owns an average 32.2% working interest.

In the fourth quarter of ~~2022,~~2023, the Company ~~completed~~is participating in an ~~acreage exchange agreement~~additional 18 horizontal wells operated by Double Eagle, located in our Hughes Alpine area of Reagan County (Studley Tracts): we are participating with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. In combination with existing acreage, this newly acquired acreage results in the Company having 100%6.82% working interest in ~~approximately 1,200 contiguous acres~~6 two-mile-long horizontals that are expected to be on production in December of this year, and ~~therefore the ability~~participating with 20% interest in 12 two and a half-mile-long laterals that are expected to ~~efficiently and cost-effectively develop the Wolfcamp formation and other prospective reservoirs through~~ ~~2-mile-long~~ ~~horizontal laterals.~~

~~Along with the 1,200 contiguous acres created from the acreage exchange,~~be on production in February of 2024. In total, the Company ~~has completed an agreement with~~is investing approximately $27 million in these 18 new horizontals and their associated facilities.

As a ~~separate prominent independent oil & gas operator to create a~~ ~~2,560-acre~~ ~~AMI for the joint development of horizontal wells. As part~~result of the ~~agreement, the Company has divested~~recent success of ~~a portion~~wells completed by Double Eagle and Civitas in Reagan County, as well as existing analogs and relatively high oil prices, both of its interest to operator for $16.1 million with the ability to acquire additional acreage from the operator located within the AMI. These exchanges should result in an approximately 50/50 ownership of thethese companies have accelerated their development ~~with the operator. This newly formed 2,560 acreage-block will allow the Company to reinvest approximately $90 million of its cash flow~~plans in the ~~drilling of as many as 18 new wells~~area where we have significant leasehold acreage. Double Eagle and Civitas each have three rigs running in ~~a very promising~~the area ~~of the Wolfcamp~~ and ~~Spraberry horizontal trend.~~

Inin the fourth quarter of ~~this year,~~2023, we ~~plan~~expect to ~~participate~~begin drilling an additional 20 wells with ~~20.8%~~Double Eagle and 14 wells with Civitas. The Company has an average of approximately 50% interest in six wells (Prime West), 8.3% interest in twelve wells (Kramer and O’Bannon), less than 1% interest in two wells (State Pink Floyd), and an average of 41% interest in 14 wells (Christi). In total, we expect to invest $84 million in these 34 wells that are all expected to be on production in the second quarter of 2024.

In addition to the drilling ~~of five~~ ~~2.5-mile-long~~ ~~horizontal~~activity described above, we expect another 12 wells, ~~in Martin County, Texas~~ operated by ~~ConocoPhillips, and~~Double Eagle, to ~~participate with 25% interest~~begin drilling on adjacent or nearby acreage in ~~the drilling of ten~~ ~~2-mile-long~~ ~~horizontals in Reagan County, Texas with Hibernia Energy III, LLC. In~~ the first quarter of ~~2023, BTA Oil Producers, LLC has indicated plans to drill nine~~ ~~2.5-mile-long~~ ~~horizontals~~2024 with an expected investment by the Company of $48 million for our 50% interest in these wells.

In summary, we are investing approximately $27 million in 18 horizontal wells operated by Double Eagle in Reagan County ~~Texas~~that are expected to begin production by February 2024, and preparing to invest $84 million in ~~which~~14 wells with Civitas Resources and 20 wells with Double Eagle in Reagan County that are expected to begin drilling in the ~~Company will~~fourth quarter of 2023 and have ~~an average 42 % interest.~~production starts in the second quarter of 2024. In addition, we ~~plan~~expect the drilling of 12 more horizontal wells to ~~participate for 47% interest in two~~ ~~3-mile-long~~ ~~horizontals with Apache Corporation in Upton County. In total, the Company will invest approximately $87 million in these 26 new wells with completions expected~~begin in the ~~Spring~~first quarter of ~~2023 and all~~2024, carrying a net capital requirement of approximately $48 million. Therefore, the total capital commitment for wells to ~~be on production~~spud by ~~mid-year~~ ~~2023.~~the end of the first quarter of 2024 is approximately $159 million.

~~Reserve Information:~~Reserves

Our interests in proved developed and undeveloped oil and gas properties ~~including the interests held by the Partnerships,~~ have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, ~~2021.~~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~~Bachelor’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. ~~See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows.~~ 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)
2019 4,381 2,914 19,995 10,628    1,833    1,017    4,547    3,608    6,214    3,931    24,542    14,235
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

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)		NGL (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 2019, in West Texas, we participated in the initial three shallow horizontals on our Kashmir tract with one of each of these wells completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry. The Company has 48% interest in two of these wells and 5.3% in one well. All three wells were brought on production in May of 2019.

In 2020, in West Texas we participated in the drilling of seven wells: one with PrimeEnergy Resources Corporation 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 of 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, ~~proved producing~~ 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 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~~ ~~2020. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells.~~

In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on our Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled in Oklahoma in 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as ~~Shut-in~~ ~~on December 31, 2018, were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract.~~

~~In 2019, in~~ our Gulf Coast ~~region,~~Region, in 2020, we added production through the recompletion of three vertical wells in Polk County, Texas: one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest. In 2020, the Company successfully recompleted one ~~additional~~ operated well in the Segno field of Polk County, Texas with a 72.5% interest.

AtOn 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 reserves where the Company has an average 47.5% interest and invested approximately $30 million dollars in these wells.~~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.

AtIn 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 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.

On December 31, 2021, the Company had 159 Mboe of ~~proved developed~~proved-developed shut-in reserves attributable to three ~~horizontal wells~~horizontals drilled and completed in Canadian County, Oklahoma, ~~in December of 2021,~~ but not yet ~~online. Three~~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 the fifteen horizontal wells that we planned to participate in located primarily in West Texas.

In 2022, the Company completed eight horizontal wells: 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 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: In Martin County, we participated with ConocoPhillips in the drilling of five 2.5-mile-long horizontal laterals (Schenecker A Tract) in which the Company has 20.83% interest with a capital investment of approximately $12.1 million. In Reagan County, we participated with Hibernia Energy III in 10 two-mile horizontals (Brynn Tract) with 25% interest with an investment of approximately $25.6 million. Also in Reagan County, we participated with Double Eagle (DE IV) in five two-mile-long horizontals (Prime East Tract) with nearly 50% interest and carried a net capital outlay of approximately $23.4 million. All twenty of these West Texas wells were brought on production by the end of the four wells were successfully completed and online in January, 2022, while one well had completion issues and has been temporarily abandoned. Regarding the four drilled but uncompleted PUD wells in Grady County, Oklahoma noted in the paragraph above, reserves previously attributed to these wells were not included in the 2021 ~~year-end~~ ~~reserve report as the operator has no near-term plans for their completion.~~third quarter of 2023.

1617

During 2022, in our West Texas horizontal drilling program, we participated with 10.3% interest in the drilling of four horizontal wells with SEM Operating Company and have received proposals for an additional 24 horizontal wells, 15 of those to begin in the fourth quarter of this year. In total, the Company is likely to invest approximately $75 million in these 28 wells. In Oklahoma, thus far in 2022, the Company is participating for 9.38% interest with Ovintiv ~~Mid-Continent~~ ~~in the drilling of four wells on our Bohlman tract in Canadian County, Oklahoma. These four wells and the four SEM wells in West Texas were placed in production during August of this year.~~ In the first quarter of 2023, ~~we intent to participate~~the Company joined Ovintiv USA, Inc. in the drilling of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest, investing approximately $645,000 (Redhead tract). These three wells were put online in June of 2023. Also in the first quarter, the Company began participation with Apache Corporation in the drilling of two 3-mile-long horizontals in Upton County, Texas (Mt. Moran). We have 49.4% interest in these wells and ~~with BTA Oil Producers~~have made a capital investment of approximately $16.1 million, and both were brought online in October.

At year-end 2022, the Company had 6,366 Mboe of proved undeveloped reserves all attributable to the 25 horizontal wells described above. In total, the Company will have invested $78 million in these 25 horizontal wells, all of which have been completed and began producing by mid-October.

Summarized in the ~~drilling~~table below (in thousands of nine 2.5 mile-long horizontals in Reagan County, Texas. 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.

~~We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in~~dollars) are the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well-test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

~~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, ~~2021, are summarized as follows (in thousands of dollars):~~2022:


	Proved Developed				Proved Undeveloped				Total								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		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
2019	$	116,592	$	82,155	$	42,700	$	17,876	$	159,292	$	100,031	$	18,419	$	81,612
2020	$	43,886	$	34,717	$	37,346	$	21,823	$	81,232	$	56,539	$	14,920	$	41,619	$	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	$	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 ~~PV 10~~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. ~~Our reserves include amounts attributable to~~ ~~non-controlling~~ ~~interests in the Partnerships. These interests represent less than 10% of our reserves.~~

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, ~~as compared to~~and $1.985 per MMBtu in ~~2020, and $2.581 per MMBtu in 2019. Through November 1, 2022, the twelve-month average of the first of the month Henry Hub index price is $6.166 per MMBtu.~~2020. Oil prices, based on the ~~NYMEX first of the month~~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, ~~as compared to~~and $39.57 per barrel in ~~2020, and $55.69 per barrel in 2019. Through November 1, 2022, the NYMEX first of the month average price was $92.37.~~2020. Since January 1, ~~2021,~~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.

RECENT ACTIVITIES

The Company’s activities include development and exploratory drilling. Our strategy is to develop the Company’s 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 somewhat lower average initial production rates but steady production and higher expected return on investment. We believe that today’s horizontal drilling and completion technologies provide superior economic results compared to vertical development 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 ~~2022,~~2023, we ~~will~~intend to 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.

InWe are actively developing our leasehold acreage in West Texas and Oklahoma and in 2023, through the third quarter, we have brought on production 25 new horizontal wells. Current activity includes the drilling of ~~2021, nine~~ ~~two-mile~~ ~~horizontal~~18 wells in ~~Upton~~Reagan County, ~~Texas, operated~~and an additional 34 wells anticipated to spud by ~~Apache Corporation,~~year-end. The following is a description of recent, current, and expected near-term drilling activities. Note, the drilling activities described below were ~~completed and brought into production.~~ previously described on a district basis in the District Information section above.

In the fourth quarter of ~~2021, three~~2022, we began participation in 20 horizontal wells in West Texas that have been completed and put on production in 2023: in Martin County, we participated with ConocoPhillips in five ~~two-mile~~2.5-mile-long horizontal wells ~~operated by Ovintiv~~(Schenecker A Tract) with 20.83% interest, investing approximately $12.1 million, in Reagan County, we participated with Hibernia Energy III in 10 ~~Mid-Continent~~two-mile horizontals (Brynn Tract) with 25% interest, investing approximately $25.6 million, and, also in ~~Canadian~~Reagan County, ~~Oklahoma~~we partnered with Double Eagle (DE IV) in five two-mile-long horizontals (Prime East Tract) with nearly 50% interest and invested approximately $23.4 million. All 20 of these West Texas wells were ~~completed and brought online~~put into production in ~~January 2022. The Company has an average of 47.5% interest in the nine wells completed with Apache and 11.25% interest in the three wells completed with Ovintiv.~~2023.

In the ~~second~~first quarter of ~~2022,~~2023, the Company ~~participated with SEM Operating Company LLC~~joined Ovintiv USA, Inc. in the drilling of four 7,900’ horizontal wells in Irion County, Texas with 10.3% interest. These four wells began their production in August. Also in the second quarter of 2022, the Company participated in the drilling of four 10,000’-longthree 3-mile-long horizontal wells in Canadian County, Oklahoma with ~~9.38% interest. These four wells, operated by Ovintiv~~ ~~Mid-Continent,~~ ~~were also put into production in early August of this year. In the fourth quarter of this year another fifteen wells are planned to be spud.~~

~~Since the start of our West Texas horizontal drilling program in 2015, we have participated in 81 wells~~1.96% interest and invested approximately ~~$130 million~~$645,000. Production of these three wells began in ~~horizontal drilling~~June. Also in the ~~Permian Basin. This includes the four wells currently in progress with SEM Operating Company in Irion County, Texas.~~

~~In Upton County, Texas, we are developing a contiguous 3,260-acre block with our joint venture partner, Apache Corporation. In this block~~first quarter of 2023, the Company ~~has 2,600 leasehold acres~~began participation with ~~interest between 14% and 56% depending on the particular lease and depth being developed. In 2018, eight successful wells were drilled horizontally by~~ Apache Corporation in the ~~Wolfcamp “B”~~drilling of this block with the Company participating for 49% interest and this is believed to be full development of the Wolfcamp “B” reservoir. Together with Apache, we are planning development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of this block. These shallower reservoirs have been ~~proven-up~~ on our offset 1,300-acre Kashmir tract. It is expected that as many as 36 additional horizontals will be developed on this 3,260-acres in the near future. This development is estimated to cost approximately $387.0 million, with the Company’s share being approximately $174.4 million. Twotwo 3-mile-long horizontals in Upton County, Texas (Mt. Moran wells). The Company has a 49.4% interest in these two wells, has invested approximately $16.1 million and the wells were brought on production in October.

In total, the Company has invested approximately $78 million in these 25 horizontal wells and their associated facilities. In December of 2022, we prepaid $32 million toward drilling costs, and the remaining $46 million in estimated drilling, completion and facilities expenses will be incurred as billed in 2023.

The success of the 22 horizontals in West Texas described above is leading to additional near-term horizontal drilling across five leasehold blocks in three counties. Both Civitas Resources and Double Eagle have ~~been slated~~accelerated their development plans and have six rigs running in the area. We are currently participating with Double Eagle in 18 wells in Reagan County and will invest an estimated $27 million in these wells that are expected to be completed and online in February 2024. In addition, we have received AFEs from Double Eagle for 20 additional horizontals in Reagan County. We will have varying interests in these 20 wells and will make an estimated capital investment of $34 million in them. Also expected soon are AFEs from Civitas for 14 wells in Reagan County where we will have an average of 41% working interest and will invest approximately $50 million. The total of these two near-term projects is $84 million. In addition, we expect drilling proposals from four operators for the development of an additional 35 horizontal wells in West Texas expected to spud in the first ~~quarter~~three quarters of ~~2023. In addition~~2024. Our interest in these 35 wells will vary from 20% to ~~the 36 prospective~~50% and we expect a capital outlay related to these wells ~~to be drilled for these three reservoirs, a fourth target reservoir, the Middle Spraberry, is also prospective for future development. The potential~~and their facilities of approximately $143 million.

All of the ~~Middle Spraberry on~~current and expected near-term activities described above encompass the ~~3,260-acre block is for 12~~drilling, completion, stimulation, and facilities of 90 new horizontal wells to be added to our proved-producing portfolio. These 90 wells will require an estimated $260 million net capital investment over the next two years. In addition, we have identified 27 horizontal locations that are a natural progression of development for three project areas in Upton and Reagan counties and are anticipated to be drilled in the 2025-2026 timeframe and ~~completed at~~will require a ~~gross cost~~net investment of approximately ~~$138.0~~$100 million.

In summary, we have invested $78 million ~~with the Company’s share being approximately $63.0 million. The actual number of wells~~in 25 new horizontals this year that are ~~eventually drilled~~all producing, and we plan to invest about $400 million in horizontal development over the next several years. Included in this $400 million estimate are the above-described investment of $27 million for 18 wells currently in the process of being completed, the $84 million in near-term development drilling for 34 wells (20 wells with Double Eagle and 14 wells with Civitas), the $143 million in expected investment for 35 wells to spud in the first three quarters of 2024, the $100 million investment in 27 drill-sites that are a natural progression of leasehold development, plus approximately $40 million in additional investments for proved and probable drill-sites that are not yet scheduled for development.

RESULTS OF OPERATIONS:

We reported net income of $22.2 million, or $11.95 per share and $10.7 million, or $5.84 per share for the nine and three months ended September 30, 2023, respectively, as ~~well as~~compared to $35.3 million, or $17.95 per share and $13.2 million, or $6.79 per share for the ~~cost~~nine and three months ended September 30, 2022, respectively. Current year net income reflects changes in production and commodity prices over the ~~timing of drilling will vary based upon many factors, including commodity market conditions.~~

~~In addition~~three and nine months ended September 30, 2022, fluctuations in gains related to the 3,260-acre block being developed, as described above, the Company has also been developing an offsetting 1,300-acre block in Upton County, Texas, with Apache Corporation as operator. In the second quartersale of ~~2019 three horizontal wells were completed~~assets and brought on production from reservoirs above the Middle Wolfcamp: one in the Wolfcamp “A”, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage. Prime holds 47.5% working interest in these reservoirs. As a result of the success of the initial three wells, nine additional horizontals followed and were completed in the third quarter of 2021. Our average 47.5% share of the cost of these nine horizontal wells was approximately $26.7 million in total. In additionchanges related to the ~~Wolfcamp “A”, Jo Mill~~valuation of derivative instruments. The significant components of income and ~~Lower Spraberry, that~~expense are now considered fully developed on the tract, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost of approximately $40.0 million with the Company’s share being approximately $18.8 million.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with ConocoPhillips in Martin County, Texas. In 2016 and 2017, four horizontal wells were drilled, completed, and put on production. The Company owns 35% to 38% interest in this joint venture acreage where we have the potential to drill as many as 36 additional wells.discussed below.

1819

Oil, gas and NGLs sales decreased $2.0 million, or 5.9% from $34.0 million for the three months ended September 30, 2022 to $32.0 million for the three months ended September 30, 2023, and $27.1 million, or 26.4% from $102.8 million for the nine months ended September 30, 2022 to $75.7 million for the nine months ended September 30, 2023. Sales vary due to changes in volumes of production sold and realized commodity prices. Our oil production reflects the natural decline in production from our previously existing wells offset by the new wells placed in production during 2023.

The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended September 30, 2023 and 2022 (excluding realized gains and losses from derivatives).


			Nine months ended September 30,
	2023		2022		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		813,561		752,500		61,061			8.1	%
Average Price Received	$	76.14	$	100.39	$	(24.25	)		(24.2	)%

Oil Revenue (In 000’s)	$	61,948	$	75,546	$	(13,598	)		(18.0	)%

Mcf of Gas Sold		2,766,128		2,456,800		309,328			12.6	%
Average Price Received	$	1.97	$	6.01	$	(4.04	)		(67.2	)%

Gas Revenue (In 000’s)	$	5,452	$	14,762	$	(9,310	)		(63.1	)%

Barrels of Natural Gas Liquids Sold		412,487		332,400		80,087			24.1	%
Average Price Received	$	20.18	$	37.54	$	(17.36	)		(46.2	)%

Natural Gas Liquids Revenue (In 000’s)	$	8,323	$	12,477	$	(4,154	)		(33.3	)%

Total Oil & Gas Revenue (In 000’s)	$	75,723	$	102,785	$	(27,062	)		(26.3	)%


			Three months ended September 30,
	2023		2022		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		323,188		244,500		78,688			32.2	%
Average Price Received	$	81.69	$	95.72	$	(14.03	)		(14.7	)%

Oil Revenue (In 000’s)	$	26,402	$	23,403	$	2,999			12.8	%

Mcf of Gas Sold		1,080,588		879,800		200,788			22.8	%
Average Price Received	$	2.29	$	7.23	$	(4.94	)		(68.3	)%

Gas Revenue (In 000’s)	$	2,472	$	6,359	$	(3,887	)		(61.1	)%

Barrels of Natural Gas Liquids Sold		161,003		122,400		38,603			31.5	%
Average Price Received	$	19.56	$	34.35	$	(14.79	)		(43.1	)%

Natural Gas Liquids Revenue (In 000’s)	$	3,149	$	4,204	$	(1,055	)		(25.1	)%

Total Oil & Gas Revenue (In 000’s)	$	32,023	$	33,966	$	(1,943	)		(5.7	)%

Oil, Natural Gas and NGL DerivativesWe do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of operations. As ~~mentioned above,~~oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in ~~West Texas,~~our revenues. The following table summarizes the ~~Company participated~~results of our derivative instruments for ~~10.3% interest with SEM Operating Company~~the three and nine months ended September 2023 and 2022:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2023		2022			2023			2022
Oil derivatives – realized losses	$	—	$	(2,668	)	$	(590	)	$	(10,389	)
Oil derivatives – unrealized gains		—		5,958			769			2,718

Total gains (losses) on oil derivatives	$	—	$	3,290		$	179		$	(7,671	)

Natural gas derivatives – realized gains (losses)	$	—	$	(1,617	)	$	24		$	(3,603	)
Natural gas derivatives – unrealized gains (losses)		—		166			211			(800	)

Total gains (losses) on natural gas derivatives	$	—	$	(1,451	)	$	235		$	(4,403	)

Total gains (losses) on oil and natural gas derivatives	$	—	$	1,839		$	414		$	(12,074	)

Prices received for the nine months ended September 30, 2023 and 2022, respectively, including the impact of derivatives were:


	2023		2022
Oil Price	$	75.42	$	86.59
Gas Price	$	1.98	$	4.54
NGLS Price	$	20.18	$	37.54

Oil and gas production expense increased $1.4 million, or 21.5% from $6.5 million for the three months ended September 30, 2022 to $7.9 million for the three months ended September 30, 2023, and increased $0.3 million, or 1.4% from $20.9 million for the nine months ended September 30, 2022 to $21.2 million for the nine months ended September 30, 2023. These changes reflect the cost savings related to wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production.

Production and ad valorem taxes decreased $0.8 million, or 36.4% from $2.2 million for the three months ended September 30, 2022 to $1.4 million for the three months ended September 30, 2023, and decreased $0.4 million, or 7.0% from $5.7 million for the nine months ended September 30, 2022 to $5.3 million for the nine months ended September 30, 2023. These decreases reflect the changes in ~~four 7,900’-long horizontal wells~~oil and gas revenues in ~~Irion County, Texas. We anticipate an investment~~the related periods.

Field service income decreased $0.2 million or 5.7% from $3.5 million for the third quarter 2022 to $3.3 million for the third quarter 2023 and increased $1.4 million, or 14.0% from $10.0 million for the nine months ended September 30, 2022 to $11.4 million for the nine months ended September 30, 2023. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of ~~$2.55~~our field service operations. These changes reflect the variance in equipment utilization and service rates during these periods.

Field service expense increased $0.5 million ~~in these wells~~or 18.5% from $2.7 million for the third quarter 2022 to $3.2 million for the third quarter 2023 and increased $1.0 million, or 11.5% from $8.7 million for the nine months ended September 30, 2022 to $9.7 million for the nine months ended September 30, 2023. Field service expenses primarily consist of wages and vehicle operating expenses which have ~~been producing since August. Also planned for this year is~~fluctuated during the ~~drilling of ten~~ ~~2-mile-long~~ ~~horizontals in Hibernia Energy, III, LLC, in Reagan County, Texas~~three and ~~the drilling of five~~ ~~2.5-mile-long~~ horizontal wells with ConocoPhillips in Martin County. The Company intends to participate for approximately 25% interest in the ten wells with Hibernia and for 20.8% interest in five wells with Conoco Phillips. Our expected investment in the drilling and completion of these wells is $36.3 million.

In the fourth quarter of 2022, the Company completed an acreage exchange agreement with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. In combination with existing acreage, this newly acquired acreage results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp formation and other prospective reservoirs through ~~2-mile-long~~ ~~horizontal laterals.~~

~~Along~~nine months ended September 30, 2023 compared with the ~~1,200 contiguous acres created~~same periods of 2022. These changes reflect the variance in equipment utilization during these periods.

Depreciation, depletion and amortization expense increased $1.3 million or 17.1% from ~~the acreage exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a~~ ~~2,560-acre~~ ~~AMI~~$7.6 million for the ~~joint development of horizontal wells. As part of~~third quarter 2022 to $8.9 million for the ~~agreement,~~third quarter 2023 and increased $1.5 million, or 7.0% from $21.4 million for the ~~Company has divested of a portion of its interest~~nine months ended September 30, 2022 to ~~operator~~$22.9 million for ~~$16.1 million with~~ the ~~ability~~nine months ended September 30, 2023. This increase reflects the expense related to ~~acquire additional acreage from~~ the operator located within the AMI. These exchanges should result in an approximately 50/50 ownership of the development with the operator. This newly formed 2,560 acreage-block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells ~~in a very promising area of the Wolfcamp and Spraberry horizontal trend.~~

In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 5,800 net leasehold acres in the Scoop/Stack Play. In 2019, we participated for an average of 4.6% interest with Newfield Exploration in twelve successful wells in Canadian County on our Slash and Wallace tracts. In 2021, we participated for 11.25% interest with Ovintiv ~~Mid-Continent~~ Inc. in four wells on our Peters tract, in Canadian County. Three of these wells were successfully completed in December 2021 and online in January 2022, while one well had completion issues and has been temporarily abandoned. At today’s product prices, payout of the Company’s $2.3 million investment in these four wells occurred in four months.

~~In April 2022, in Oklahoma, the Company and Ovintiv~~ ~~Mid-Continent~~ ~~began drilling four horizontal wells on our Bohlman tract in the same area as the successful Peters wells. All four of the Bohlman wells have been drilled, completed, and were~~ placed on production in ~~early August.. The Company is participating with 9.38% interest~~2023.

General and administrative expense decreased $3.4 million, or 29.6% from $11.5 million for the nine months ended September 30, 2022 to $8.1 million for the nine months ended September 30, 2023, and increased $0.2 million, or 8.0% from $2.5 million for the three months ended September 30, 2022 to $2.7 million for the three months ended September 30, 2023. These changes are primarily related to employee compensation and benefits.

Interest expense decreased $0.4 million, or 50.0% from $0.8 million for the nine months ended September 30, 2022 to $0.4 million for the nine months ended September 30, 2023, and decreased $0.2 million, or 66.7% from $0.3 million for the three months ended September 30, 2022 to $0.1 million for the three months ended September 30, 2023. This decrease reflects the increase in ~~these wells with an approximate investment $2.45 million. In May, we sold 241 acres~~rates and lower current borrowings under our revolving credit agreement.

Income tax expense for the September 30, 2023 and 2022 periods varied due to the change in ~~Canadian County, Oklahoma for proceeds of $845,000, and in August another 113 acres for $423,700. Both of these sales were of~~ ~~non-strategic~~ ~~acreage and the Company retained its interest in existing wells and a small overriding royalty interest in future development.~~

~~We believe our 5,800~~ net leasehold acres in Oklahoma have the resource potential to support the drilling of as many as 50 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. Should we choose to participate in future development, our share of the capital expenditures would be approximately 34.6 million at a 10% ownership level; the Company will otherwise sell its rights for cash or cash plus a royalty or working interest.income.

LIQUIDITY AND CAPITAL RESOURCES

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For ~~2022,~~2023, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our ~~2022~~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 nine months ended September 30, ~~2022~~2023 was ~~$47.3~~$78.1 million, compared to ~~$18.8~~$62.7 million in the prior ~~period.~~year.

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. ~~Accordingly,~~If the ~~Company has in place the following swap agreements for oil and natural gas.~~

   2022    2023    2022    2023
Swap Agreements

Natural Gas (MMBTU)
   279,000    254,000    $    $ 3.60
Oil (barrels)
   79,300    70,700    $    $ 69.50

~~In the first quarter~~borrowing base utilization percentage is less than 15% of ~~2022, the Company participated in the drilling of four wells with SEM Operating Company in Irion County, Texas for 10.3% interest and in April of this year began participating with Ovintiv~~ ~~Mid-Continent~~ ~~in four wells in Canadian County, Oklahoma with 9.38% interest.~~

These eight wells have been completed and were put on production in early August. In addition, the Company has received drilling proposals for an additional 26 horizontal wells to be drilled in West Texas with 15 of these slated to begin drilling this year. In total available borrowings, the Company is ~~likely~~not required to ~~invest approximately $86 million in these 26 wells.~~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 ~~$75~~$65 million. As of ~~August~~November 15, ~~2022,~~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 December ~~2022.~~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.

In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through three transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests.

~~In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for proceeds of $845,000 and a retained over-riding royalty interest.~~

~~In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.~~

In November of 2022, the Company completed an acreage exchange with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. When combined with currently held acreage, this acreage exchange results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp and other prospective reservoirs through ~~2-mile-long~~ ~~horizontal laterals. In addition to this exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a~~ ~~2,560-acre~~ AMI for the joint development of horizontal wells. As part of the plan, the Company has divested a portion of its interest to the operator for $16.1 million and has the right to acquire additional acreage from the operator within the AMI. These exchanges should result in an approximate 50/50 ownership of the AMI development with the operator. This newly formed 2,560 acreage block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.

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

The Company has a stock repurchase program in place, spending under this program during the first nine months of ~~2022~~2023 was ~~$5.0~~$6.6 million. The Company expects continued spending under the stock repurchase program in ~~2022.~~2023.

~~RESULTS OF OPERATIONS~~

~~2022 and 2021 Compared~~

We reported net income of $35.3 million, or $17.95 per share and $13.2 million, or $6.79 per share for the nine and three months ended September 30, 2022, respectively, as compared to net losses of $1.2 million, or $(0.58) per share and $5.0 million, or $(2.52) per share for the three and nine months ended September 30, 2021, respectively. Current year net income reflects increases in production and commodity price increases over the three and nine months ended September 30, 2022, fluctuations in gains related to the sale of assets and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

~~Oil, gas and NGLs sales~~ increased $15.9 million, or 87.8% from $18.1 million for the three months ended September 30, 2021 to $34.0 million for the three months ended September 30, 2022, and $56.7 million, or 122.9% from $46.1 million for the nine months ended September 30, 2021 to $102.8 million for the nine months ended September 30, 2022

The following tables summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2022 and 2021 (excluding realized gains and losses from derivatives).

      Nine months ended September 30,
   2022    2021    Increase /
(Decrease)    Increase /
(Decrease)
Barrels of Oil Produced
   752,500    480,000    272,500    56.8 %
Average Price Received
   $ 100.39    $ 63.28    $ 37.11    58.6 %







Oil Revenue (In 000’s)
   $ 75,546    $ 30,376    $ 45,170.00    148.7 %







Mcf of Gas Sold
   2,456,800    2,395,000    61,800    2.6 %
Average Price Received
   $ 6.01    $ 3.32    $ 2.69    81.0 %







Gas Revenue (In 000’s)
   $ 14,762    $ 7,948    $ 6,814.00    85.7 %







Barrels of Natural Gas Liquids Sold
   332,400    298,000    34,400    11.5 %
Average Price Received
   $ 37.54    $ 26.11    $ 11.43    43.8 %







Natural Gas Liquids Revenue (In 000’s)
   $ 12,477    $ 7,781    $ 4,696    60.4 %







Total Oil & Gas Revenue (In 000’s)
   $ 102,785    $ 46,105    $ 56,680    122.9 %

      Three months ended September 30,
   2022    2021    Increase /
(Decrease)    Increase /
(Decrease)
Barrels of Oil Produced
   244,500    152,000    92.500    60.9 %
Average Price Received
   $ 95.72    $ 68.70    $ 27.02    39.3 %







Oil Revenue (In 000’s)
   $ 23,403    $ 10.442    $ 12,961    124.1 %







Mcf of Gas Sold
   879,800    950,000    (70,200 )    (7.39 )%
Average Price Received
   $ 7.23    $ 4.21    $ 3.02    71.7 %







Gas Revenue (In 000’s)
   $ 6,359    $ 3,998    $ 2,361    59.1 %







Barrels of Natural Gas Liquids Sold
   122,400    103,000    19,400    18.8 %
Average Price Received
   $ 34.35    $ 35.26    $ (0.91 )    (2.59 )%







Natural Gas Liquids Revenue (In 000’s)
   $ 4,204    $ 3,632    $ 572    15.7 %







Total Oil & Gas Revenue (In 000’s)
   $ 33,966    $ 18,072    $ 15,894    87.9 %

~~Oil, Natural Gas and NGL Derivatives~~ ~~We do not apply hedge accounting to any of our commodity-based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as~~ ~~mark-to-market~~ ~~adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile,~~ ~~mark-to-market~~ ~~accounting treatment creates volatility in our revenues.~~

~~Field service income~~ increased $1.4 million or 58.3% from $2.4 million for the third quarter 2021 to $3.8 million for the third quarter 2022 and increased $4.6 million, or 74.2% from $6.2 million for the nine months ended September 30, 2021 to $10.8 million for the nine months ended September 30, 2022. These changes reflect the increase in utilization and rates resulting from the oil and gas price increases during these periods. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

~~Lease operating expense~~ increased $2.3 million or 35.9% from $6.4 million for the third quarter 2021 to $8.7 million for the third quarter 2022 and increased $11.3 million or 73.9% from $15.3 million for the nine months ended September 30, 2021 to $26.6 million for the nine months ended September 30, 2022. This increase is primarily due to higher production taxes related to higher commodity prices during 2022 combined with workover expenses and lease operating expense related to higher lifting cost properties returned to production as commodity prices increased.

~~Field service expense~~ increased $0.1 million or 3.4% from $2.9 million for the third quarter 2021 to $3.0 million for the third quarter 2022 and increased $3.3 million, or 53.2% from $6.2 million for the nine months ended September 30, 2021 to $9.5 million for the nine months ended September 30, 2022. Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and nine months ended September 30, 2022 compared with the same periods of 2021. These changes reflect the increase in utilization resulting from the oil and gas price increases during these periods.

~~Depreciation, depletion, amortization and accretion on discounted liabilities~~ increased $0.8 million, or 11.6% from $6.9 million for the third quarter 2021 to $7.7 million for the third quarter 2022 and $1.9 million, or 9.5% from $20.0 million for the nine months ended September 30, 2021 to $21.9 million for the nine months ended September 30, 2022. These increases reflect the change in the property basis combined with production increases in 2022.

~~General and administrative expense~~ increased $5.3 million, or 85.5% from $6.2 million for the nine months ended September 30, 2021 to $11.5 million for the nine months ended September 30, 2022, and increased $0.5 million, or 25.0% from $2.0 million for the three months ended September 30, 2021 to $2.5 million for the three months ended September 30, 2022. This increase in 2022 is primarily due to increased employee compensation and benefits.

~~Interest expense~~ decreased from $0.5 million for the third quarter 2021 to $0.3 million for the third quarter 2022 and from $1.5 million for the nine months ended September 30, 2021 to $0.8 million for the nine months ended September 30, 2022. This decrease reflects the increase in rates and reduced borrowings under our revolving credit agreement.

~~Income tax benefit/expense~~ ~~for the September 30, 2022 and 2021 periods varied due to the change in net income or loss for those periods.~~

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4.

CONTROLS AND PROCEDURES

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the first nine months of ~~2022~~2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

None.

Item 1A.

RISK FACTORS

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

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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

~~During the nine months ended September 30, 2022,~~ There was no purchase of equity securities by the Company ~~purchased~~during the ~~following shares of common stock as treasury shares.~~period covered by this report.


2022 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)
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		2,981	$	76.21		144,740		9,500	$	90.36		45,044
February		5,948	$	73.26		138,792		3,000	$	90.32		42,044
March		2,259	$	75.36		136,533		18,940	$	85.44		23,104
April		3,426	$	74.82		133,107		10,560	$	86.21		12,544
May		5,963	$	82.37		127,144		11,000	$	86.69		1,544
June		18,855	$	85.18		108,289		7,500	$	100.35		294,044
July		15,645	$	79.68		92,644		4,000	$	94.00		290,044
August		5,500	$	87.99		87,144		4,000	$	98.09		286,044
September		800	$	92.80		86,344		4,000	$	109.73		282,044

Total/Average		61,377	$	81,33				72,500	$	90.64

(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 and June 7, 2023, the Board of Directors of the Company approved an additional 500,000, 200,000 and ~~200,000~~300,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of ~~3,700,000~~4,000,000 shares have been authorized to date under this program. Through September 30, ~~2022,~~2023, a total of ~~3,615,756~~3,717,956 shares have been repurchased under this program for ~~$78,266,619~~$89,053,479 at an average price of ~~$22,15~~$23.95 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

~~Non~~None

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)

101.SCH		Inline XBRL Taxonomy Extension Schema Document (filed herewith)

101.CAL		Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)

101.DEF		Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)

101.LAB		Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith)

101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)

104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SIGNATURES

Pursuant to the requirements of ~~Section 13 or 15(d) of~~ the Securities and Exchange Act of 1934, ~~the registrant~~Registrant has duly caused this ~~report~~Report to be signed on its behalf by the undersigned thereunto duly authorized.


		PrimeEnergy Resources Corporation
			~~PRIMEENERGY RESOURCES CORPORATION~~ (Registrant)

~~Dated:~~ November ~~21, 2022~~			~~By:~~17, 2023	/s/ Charles E. Drimal, Jr.
(Date)				Charles E. Drimal, Jr.
	President
	~~Chairman,~~ Principal Executive Officer

	/s/ Beverly A. Cummings
November 17, 2023	Beverly A. Cummings
	Executive Vice President
	Principal Financial Officer


	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Revenues:
Oil	$	26,402		$	23,403		$	61,948		$	75,546
Natural gas		2,472			6,359			5,452			14,762
Natural gas liquids		3,149			4,204			8,323			12,477
Field service		3,337			3,509			11.442			9,998
Realized loss on derivative instruments, net		—			(4,285	)		(566	)		(13,992	)
Unrealized gain on derivative instruments, net		—			6,124			980			1,918
Other income		—			—			38			29

Total revenues		35,360			39,314			87,617			100,738
Costs and expenses:
Oil and gas production		7,898			6,476			21,171			20,888
Production and ad valorem taxes		1,445			2,201			5,308			5,721
Field service		3,166			2,670			9,700			8,725
Depreciation, depletion and amortization		8,924			7,569			22,857			21,386
Accretion of discount on asset retirement obligations		183			163			550			545
General and administrative		2,714			2,453			8,086			11,543

Total costs and expenses		24,330			21,532			67,672			68,808
Gain on sale and exchange of assets		2,102			494			8,206			15,330

Income from operations		13,132			18,276			28,151			47,260
Other income (expense)
Interest expense		(133	)		(253	)		(428	)		(752	)
Interest income		113			8			286			8

Income before income taxes		13,112			18,031			28,009			46,516
Income tax provision		2,392			4,877			5,789			11,237

Net income	$	10,720		$	13,154		$	22,220		$	35,279

Net income per share attributable to common stockholders:
Basic	$	5.84		$	6.79		$	11.95		$	17.95
Diluted	$	4.13		$	4.88		$	8.49		$	12.96
Weighted average shares outstanding:
Basic		1,834,709			1,937,091			1,859,084			1,965,334
Diluted		2,593,924			2,694,906			2,617,758			2,722,522


	Three Months Ended September 30,						Nine Months Ended September 30,
	2022			2021			2022			2021
Revenues
Oil sales	$	23,403		$	10,442		$	75,546		$	30,376
Natural gas sales		6,359			3,998			14,762			7,948
Natural gas liquids sales		4,204			3,632			12,477			7,781
Realized (loss) on derivative instruments, net		(4,285	)		(1,983	)		(13,992	)		(2,896	)
Field service income		3,846			2,415			10,822			6,215
Unrealized gain (loss) on derivative instruments, net		6,124			(1,194	)		1,918			(7,162	)
Other income		—			1			29			30

Total Revenues		39,651			17,311			101,562			42,292
Costs and Expenses
Lease operating expense		8,679			6,396			26,613			15,298
Field service expense		3,005			2,925			9,545			6,180
Depreciation, depletion, amortization and accretion on discounted liabilities		7,732			6,883			21,931			19,990
General and administrative expense		2,453			1,984			11,543			6,183

Total Costs and Expenses		21,869			18,188			69,632			47,651
Gain on Sale and Exchange of Assets		494			5			15,330			111

Income (Loss) from Operations		18,276			(872	)		47,260			(5,248	)
Other Income (Expense)
Interest Income		8			—			8			—
Interest Expense		(253	)		(462	)		(752	)		(1,469	)

Income (Loss) Before Income Taxes		18,031			(1,334	)		46,516			(6,717	)
Income Taxes Expense (Benefit)		4,877			(186	)		11,237			(1,700	)

Net Income (Loss)		13,154			(1,148	)		35,279			(5,017	)
Less: Net Income Attributable to Non-Controlling Interests		—			15			—			4

Net Income (Loss) Attributable to PrimeEnergy	$	13,154		$	(1,163	)	$	35,279		$	(5,021	)

Basic Income (Loss) Per Common Share	$	6.79		$	(0.58	)	$	17.95		$	(2.52	)

Diluted Income (Loss) Per Common Share	$	4.88		$	(0.58	)	$	12.96		$	(2.52	)


	2022			2021			2023			2022
Cash Flows from Operating Activities:
Net Income (Loss)	$	35,279		$	(5,017	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		21,931			19,990
Gain on sale of properties		(15,330	)		(111	)
Unrealized (gain) loss on derivative instruments, net		(1,918	)		7,162
Provision for deferred income taxes		8,775			(1,700	)
Changes in operating assets and liabilities:
Net Income							$	22,220		$	35,279
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization								22,857			21,386
Gain on sale and exchange of assets								(8,206	)		(15,330	)
Accretion of discount on asset retirement obligations								550			545
Unrealized gain on derivative instruments, net								(980	)		(1,918	)
Deferred income taxes								3,320			8,775
Changes in assets and liabilities:
Accounts receivable		(2,735	)		(7,120	)		(5,225	)		(2,735	)
Due from related parties								388			—
Due to related parties		61			(4	)		398			61
Other assets		(308	)		(655	)
Prepaids obligations								32,426			(308	)
Accounts payable		(1,114	)		6,170			449			(1,114	)
Accrued liabilities		2,705			109			2,700			2,705
Other, net								(173	)		—

Net Cash Provided by Operating Activities		47,346			18,824			70,724			47,346

Cash Flows from Investing Activities:
Capital expenditures		(7,972	)		(11,301	)
Capital expenditures, including exploration expense								(67,069	)		(7,972	)
Proceeds from sale of properties and equipment		15,330			111			7,434			15,330

Net Cash Provided by (Used in) Investing Activities		7,358			(11,190	)		(59,635	)		7,358

Cash Flows from Financing Activities:
Purchase of stock for treasury		(4,992	)		—			(6,572	)		(4,992	)
Purchase of non-controlling interests		—			(6	)
Proceeds from long-term bank debt and other long-term obligations		—			3,000
Repayment of long-term bank debt and other long-term obligations		(36,000	)		(8,000	)		(11,270	)		(36,000	)

Net Cash (Used in) Financing Activities		(40,992	)		(5,006	)
Net Cash Used in Financing Activities								(17,842	)		(40,992	)

Net Increase in Cash and Cash Equivalents		13,712			2,628
Net (Decrease) Increase in Cash and Cash Equivalents								(6,753	)		13,712
Cash and Cash Equivalents at the Beginning of the Period		10,347			996			26,543			10,347

Cash and Cash Equivalents at the End of the Period	$	24,059		$	3,624		$	19,790		$	24,059

Supplemental Disclosures:
Income taxes paid	$	61		$	—		$	9,288		$	61
Interest paid	$	714		$	1,384		$	450		$	714


(Thousands of dollars)	September 30, 2022			December 31, 2021			September 30, 2023		December 31, 2022
Accounts Receivable:
Joint interest billing	$	2,338		$	1,902		$	1,931	$	1,806
Trade receivables		1,780			1,429			2,193		1,762
Oil and gas sales		13,095			11,154			13,523		8,894
Other		101			94			63		21

		17,314			14,579		17,710		12,483
Less: Allowance for doubtful accounts		(371	)		(371	)

Total	$	16,943		$	14,208

Accounts Payable:
Trade	$	1,428		$	2,390
Royalty and other owners		3,605			2,802
Partner advances		1,062			1,209
Other		73			881

Total	$	6,168		$	7,282


(Thousands of dollars)	September 30, 2023			December 31, 2022
Less: Allowance for doubtful accounts		(338	)		(336	)

Total	$	17,372		$	12,147

Accounts Payable:
Trade	$	7,188		$	5,142
Royalty and other owners		3,276			3,600
Partner advances		954			1,111
Other		482			1,598

Total	$	11,900		$	11,451


	Common Stock
	Shares			Amount		Additional Paid-In Capital		Retained Earnings			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity
Balance at December 31, 2021		1,992,077		$	281	$	7,555	$	128,902		$	(37,647	)	$	99,091		$	—		$	99,091
Purchase 61,377 shares of Common stock		(61,377	)		—		—		—			(4,992	)		(4,992	)		—			(4,992	)
Net Income		—			—		—		35,279			—			35,279			—			35,279
Balance at September 30, 2022		1,930,700		$	281	$	7,555	$	164,181		$	(42,639	)	$	129,378		$	—		$	129,378

Balance at December 31, 2020		1,994,177		$	281	$	7,541	$	126,804		$	(37,502	)	$	97,124		$	874		$	97,998
Net (Loss) Income									(5,021	)					(5,021	)		4			(5,017	)
Purchase of non- controlling interest		—			—		19		—			—			19			(25	)		(6	)

Balance at September 30, 2021		1,994,177		$	281	$	7,560	$	121,783		$	(37,502	)	$	92,122		$	853		$	92,975


	Common Stock					Additional Paid-In Capital		Retained Earnings		Treasury Stock			Total Equity
	Shares Outstanding			Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock			Total Equity
Balance at December 31, 2022		1,901,000		$	281	$	7,555	$	177,566	$	(45,049	)	$	140,353
Purchase of treasury 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
Purchase of treasury stock		(29,060	)		—		—		—		(2,616	)		(2,616	)
Net income		—			—		—		10,090		—			10,090

Balance at June 30, 2023		1,840,500		$	281	$	7,555	$	189,066	$	(50,413	)	$	146,489
Purchase of treasury stock		(12,000	)		—		—		—		(1,208	)		(1,208	)
Net income		—			—		—		10,720		—			10,720

Balance at September 30, 2023		1,828,500		$	281	$	7,555	$	199,786	$	(51,621	)	$	156,001


(Thousands of dollars)	Operating Leases
2022		174
2023		251
2024		107
2025		27

Total undiscounted lease payments	$	559
Less: Amount associated with discounting		(54	)

Net operating lease liabilities	$	505


(Thousands of dollars)	Operating Leases
2023	$	187
2024		275
2025		45

Total undiscounted lease payments	$	507
Less: Amount associated with discounting		(49	)

Total net operating lease liabilities	$	458
Less: Current portion included in current portion of asset retirement and other long-term obligations		381

Non-current portion included in other long-term obligations	$	77


(Thousands of dollars)	September 30, 2023
Asset retirement obligation at December 31, 2022	$	15,443
Additions		16
Dispositions		(1,161	)
Liabilities settled		(2,727	)
Accretion of discount		550

Asset retirement obligation at September 30, 2023	$	12,121
Less current portion of asset retirement obligations		554

Asset retirement obligations, long-term		11,567


September 30, 2022	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at September 30, 2022
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	308		$	308

Total assets	$	—	$	—	$	308		$	308

Liabilities
Commodity derivative contracts	$	—	$	—	$	(3,975	)	$	(3,975	)

Total liabilities	$	—	$	—	$	(3,975	)	$	(3,975	)


December 31, 2021	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, 2021
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	$	—	$	—	$	(5,585	)	$	(5,585	)	$	—	$	—	$	(1,190	)	$	(1,190	)