Table of Contents
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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, 2023
Or
 
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From
        
    
    
    
to
    
        
    
    
Commission File Number
0-7406
 
 
PrimeEnergy Resources Corporation
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
   
84-0637348
(State or other jurisdiction of
incorporation or organization)
   
(I.R.S. employer

Identification No.)
9821 Katy Freeway, Houston, Texas 77024
(Address of principal executive offices)
(713)
735-0000
(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
 
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
  
Trading
Symbol(s)
  
Name of each exchange
on which registered
Common Stock, $0.10 par value
  
PNRG
  
NASDAQ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days.    Yes  ☒    No  ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation
S-T
(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated
filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule
12b-2
of the Exchange Act.
 
Large Accelerated Filer   ☐    Accelerated Filer   ☐
Non-Accelerated
Filer		   ☒    Smaller Reporting Company   ☒
     Emerging growth company   ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2
of the Exchange Act).    Yes  ☐    No  ☒
The number of shares outstanding of each class of the Registrant’s Common Stock as of November 13, 2023 was: Common Stock, $0.10 par value 1,820,576 shares.
 
 
 

Table of Contents

PrimeEnergy Resources Corporation

Index to Form 10-Q

September 30, 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  

Consolidated Balance Sheets –September 30, 2023 and December 31, 2022

      4  

Consolidated Statements of Operations – For the three and nine months ended September 30, 2023 and 2022

      5  

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, 2023 and 2022

      7  

Notes to Consolidated Financial Statements – September 30, 2023

      8-13  

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation

      14-22  

Item 3. Quantitative and Qualitative Disclosures About Market Risk

      22  

Item 4. Controls and Procedures

      22  

Part 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  

 

Table of Contents

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.

 

1

Table of Contents
  (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.

 

2

Table of Contents

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.

 

3

Table of Contents
The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term.http://fasb.org/us-gaap/2023#Revenueshttp://fasb.org/us-gaap/2023#Revenueshttp://fasb.org/us-gaap/2023#Revenueshttp://fasb.org/us-gaap/2023#OperatingLeaseLiability
PART I—FINANCIAL INFORMATION
 
Item 1.
FINANCIAL STATEMENTS
PRIMEENERGY RESOURCES CORPORATION
C
ONSOLIDATED
B
ALANCE
S
HEETS
(in Thousands, except share data)
 
    
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 are an integral part of these consolidated financial statements
 
4
PRIMEENERGY RESOURCES CORPORATION
C
ONSOLIDATED
S
TATEMENTS
O
F
O
PERATIONS
– Unaudited
Three and nine months ended September 30, 2023 and 2022
(Thousands of dollars, except per share amounts)
 
    
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  
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 are an integral part of these consolidated financial statements
 
5
PRIMEENERGY RESOURCES CORPORATION
C
ONSOLIDATED
S
TATEMENT
O
F
E
QUITY
– Unaudited
Three and nine months Ended September 30, 2023 and 2022
(Thousands of dollars, except share amounts)
 
    
Common Stock
     
Additional
Paid-In

Capital
     
Retained
Earnings
     
Treasury
Stock
    
Total
Equity
  
    
Shares
Outstanding
    
Common
Stock
  
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  
  
 
 
    
 
 
     
 
 
     
 
 
     
 
 
    
 
 
  
 
    
Common Stock
     
Additional
Paid-In

Capital
     
Retained
Earnings
     
Treasury
Stock
    
Total
Equity
  
    
Shares
Outstanding
    
Common
Stock
  
Balance at December 31, 2021
      1,992,077     $ 281      $ 7,555      $ 128,902      $ (37,647 )    $ 99,091  
Purchase of treasury stock
      (11,188 )               (833 )      833  
Net income
      —         —          —          11,142        —         11,142  
  
 
 
    
 
 
     
 
 
     
 
 
     
 
 
    
 
 
  
Balance at March 31, 2022
      1,980,889     $ 281      $ 7,555      $ 140,044      $ (38,480 )    $ 109,400  
Purchase of treasury stock
      (28,244 )      —          —          —          (2,354 )      (2,354 ) 
Net income
      —         —          —          10,983        —         10,983  
  
 
 
    
 
 
     
 
 
     
 
 
     
 
 
    
 
 
  
Balance at June 30, 2022
      1,952,645     $ 281      $ 7,555      $ 151,027      $ (40,834 )    $ 118,029  
Purchase of treasury stock
      (21,945 )      —          —          —          (1,805 )      (1,805 ) 
Net income
      —         —          —          13,154        —         13,154  
  
 
 
    
 
 
     
 
 
     
 
 
     
 
 
    
 
 
  
Balance at September 30, 2022
      1,930,700     $ 281      $ 7,555      $ 164,181      $ (42,639 )    $ 129,378  
  
 
 
    
 
 
     
 
 
     
 
 
     
 
 
    
 
 
  
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 are an integral part of these consolidated financial statements
 
6
PRIMEENERGY RESOURCES CORPORATION
C
ONSOLIDATED
S
TATEMENTS
O
F
C
ASH
F
LOWS
– Unaudited
Nine Months Ended September 30, 2023 and 2022
(Thousands of dollars)
 
    
2023
    
2022
  
Cash Flows from Operating Activities:
     
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
      (5,225 )      (2,735 ) 
Due from related parties
      388       —    
Due to related parties
      398       61  
Prepaids obligations
      32,426       (308 ) 
Accounts payable
      449       (1,114 ) 
Accrued liabilities
      2,700       2,705  
Other, net
      (173 )      —    
  
 
 
    
 
 
  
Net Cash Provided by Operating Activities
      70,724       47,346  
  
 
 
    
 
 
  
Cash Flows from Investing Activities:
     
Capital expenditures, including exploration expense
      (67,069 )      (7,972 ) 
Proceeds from sale of properties and equipment
      7,434       15,330  
  
 
 
    
 
 
  
Net Cash Provided by (Used in) Investing Activities
      (59,635 )      7,358  
  
 
 
    
 
 
  
Cash Flows from Financing Activities:
     
Purchase of stock for treasury
      (6,572 )      (4,992 ) 
Repayment of long-term bank debt and other long-term obligations
      (11,270 )      (36,000 ) 
  
 
 
    
 
 
  
Net Cash Used in Financing Activities
      (17,842 )      (40,992 ) 
  
 
 
    
 
 
  
Net (Decrease) Increase in Cash and Cash Equivalents
      (6,753 )      13,712  
Cash and Cash Equivalents at the Beginning of the Period
      26,543       10,347  
  
 
 
    
 
 
  
Cash and Cash Equivalents at the End of the Period
    $ 19,790     $ 24,059  
  
 
 
    
 
 
  
Supplemental Disclosures:
     
Income taxes paid
    $ 9,288     $ 61  
Interest paid
    $ 450     $ 714  
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 are an integral part of these consolidated financial statements
 
7
PRIMEENERGY RESOURCES CORPORATION
N
OTES
TO
C
ONSOLIDATED
F
INANCIAL
S
TATEMENTS
September 30, 2023
(1) Basis of Presentation:
The accompanying consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form
10-K
for the year ended December 31, 2022. In the opinion of management, the accompanying interim consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s consolidated balance sheets as of September 30, 2023, and December 31, 2022, the consolidated results of operations, cash flows and equity for the nine months ended September 30, 2023, and 2022.
As of September 30, 2023, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form
10-K
for the fiscal year ended December 31, 2022. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.
(2) Acquisitions and Dispositions
2023 Transactions
:
In the first quarter of 2023, the Company sold 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.
In the second quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320
non-core
acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.
In the third quarter of 2023, the Company sold a
non-core
38.25-acre
leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original ownership in such wells. In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres.
In November 2023, the Company sold 136 surface acres in Oklahoma for proceeds of $306,000.
2022 Transactions
:
In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.0 million.
In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for $845,000.
In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.
(3) Additional Balance Sheet Information:
Certain balance sheet amounts are comprised of the following:
 
(Thousands of dollars)
   
September 30,
2023
     
December 31,
2022
  
Accounts Receivable:
      
Joint interest billing
    $ 1,931      $ 1,806  
Trade receivables
      2,193        1,762  
Oil and gas sales
      13,523        8,894  
Other
      63        21  
  
 
 
     
 
 
  
     17,710      12,483  
 
8
(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  
  
 
 
     
 
 
  
 
(Thousands of dollars)
   
September 30,
2023
     
December 31,
2022
  
Accrued Liabilities:
      
Compensation and related expenses
    $ 4,837      $ 9,743  
Property costs
      17,889        4,718  
Taxes
      3,024        9,352  
Operating costs
      2,322        1,695  
Other
      378        242  
  
 
 
     
 
 
  
Total
    $ 28,450      $ 25,750  
  
 
 
     
 
 
  
(4) Long-Term Debt:
Bank Debt:
The Company maintains a revolving corporate credit facility (the “Credit Facility”) with a group of financial institutions with aggregate loan commitments of $300 million, subject to a borrowing base that is determined semi-annually, with a maturity date of June 1, 2026. As of December 31, 2022, the borrowing base was $75 million and the Company had $11 million outstanding borrowings under the Credit Facility.
The Credit Facility requires the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, and places restrictions on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements. As of June 30, 2023, the Company was in compliance with its debt covenants. Borrowings bear interest, at the option of the Company, based on a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) Adjusted Term SOFR (secured overnight financing rate as administered by the Federal Reserve Bank of New York) for a
one-month
tenor in effect on such day plus 1.00%, or a Term SOFR. Both options are subject to an additional margin, determined based upon the utilization of the borrowing base then in effect, ranging from 2.25% to 4.25% per annum. The Company also pays commitment fees on undrawn amounts under the Credit Facility of 0.50% per annum. Borrowings under the Credit Facility are secured by substantially all of the Company’s oil and gas properties.
Effective January 20, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and Prime of the 2022 Credit Agreement resulted in an adjustment to decrease the amount of the Borrowing Base available from $75 million to $60 million until such time as the next redetermination date as required by the agreement.
Effective July 24, 2023 the borrowing base was increased to $65 million. The borrowing base as of September 30, 2023 remained at $65 million and the Company hand no outstanding borrowings under the Credit Facility at that time.
As of November 15, 2023 the Company had no outstanding borrowings under the Credit Facility.
(5) Other Long-Term Obligations and Commitments:
Operating Leases:
The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the
 
9
lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 7.82%. Certain leases may contain variable costs above the minimum required payments and are not included in the
right-of-use
assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet.
Operating lease costs for the nine months ended September 30, 2023 and 2022 were $525,000 and $468,000, respectively. Cash payments included in the operating lease cost for the nine months ended September 30, 2023 and 2022 were $552,000 and $499,000, respectively. The weighted-average remaining operating lease terms as of September 30, 2023 and 2022 were 7.88 months and 6.33 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for payments of $187,000 in 2023, $275,000 in 2024 and $45,000 in 2025.
Rent expense for office space for the nine months ended September 30, 2023 and 2022 was $555,000 and $563,000, respectively.
The payment schedule for the Company’s operating lease obligations as of September 30, 2023 is as follows:
 
(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  
  
 
 
  
Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2023 is as follows:
 
(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  
  
 
 
  
The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.
 
10
(6) Contingent Liabilities:
The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
(7) Stock Options and Other Compensation:
In May 1989,
non-statutory
stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 30, 2023 and 2022, the remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.
(8) Related Party Transactions:
Amounts due to or from related parties primarily represent receipts or expenses, related to oil and gas properties, collected or paid by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors.
(9) Financial Instruments
Fair Value Measurements:
Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at September 30, 2023 and December 31, 2022:
 
September 30, 2023
   
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,
2023
  
(Thousands of dollars)
                            
Assets
            
Commodity derivative contracts
    $ —      $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Total assets
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Liabilities
            
Commodity derivative contracts
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Total liabilities
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
 
December 31, 2022
   
Quoted Prices in
Active Markets
For Identical
Assets (Level 1)
     
Significant
Other
Observable
Inputs (Level 2)
     
Significant
Unobservable
Inputs (Level 3)
     
Balance at
December 31,
2022
  
(Thousands of dollars)
                            
Assets
            
Commodity derivative contracts
    $ —        $ —        $ 210      $ 210  
  
 
 
     
 
 
     
 
 
     
 
 
  
Total assets
    $ —        $ —        $ 210      $ 210  
  
 
 
     
 
 
     
 
 
     
 
 
  
Liabilities
            
Commodity derivative contracts
    $ —        $ —        $ (1,190 )     $ (1,190 ) 
  
 
 
     
 
 
     
 
 
     
 
 
  
Total liabilities
    $ —        $ —        $ (1,190 )     $ (1,190 ) 
  
 
 
     
 
 
     
 
 
     
 
 
  
The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.
The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.
 
11
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, 2023.
 
(Thousands of dollars)
       
Net Liabilities – December 31, 2022
    $ (980 ) 
Total realized and unrealized gains (losses):
   
Included in earnings (a)
      414  
Purchases, sales, issuances and settlements
      566  
  
 
 
  
Net Liabilities — 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.
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, 2023 and December 31, 2022:
 
           
Fair Value
  
(Thousands of dollars)
   
Balance Sheet Location
     
September 30,
2023
     
December 31,
2022
  
Asset Derivatives:
         
Derivatives not designated as cash-flow hedging instruments:
         
Crude oil commodity contract
      Derivative asset      $ —        $ 162  
Natural gas commodity contract
      Derivative asset        —          48  
     
 
 
     
 
 
  
Total
       $ —        $ 210  
     
 
 
     
 
 
  
Liability Derivatives:
         
Derivatives not designated as cash-flow hedging instruments:
         
Crude oil commodity contracts
      Derivative liability      $ —        $ (931 ) 
Natural gas commodity contracts
      Derivative liability        —          (259 ) 
     
 
 
     
 
 
  
Total
       $ —        $ (1,190 ) 
     
 
 
     
 
 
  
Total derivative instruments
       $ —        $ (980 ) 
     
 
 
     
 
 
  
The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine months ended September 30, 2023 and 2022:
 
          
Amount of gain (loss)

recognized in in o me
  
(Thousands of dollars)
   
Location of gain/loss recognized in income
    
2023
     
2022
  
Derivatives not designated as cash-flow hedge instruments:
        
Natural gas commodity contracts
      Unrealized gain (loss) on derivative instruments, net       211        (800 ) 
Crude oil commodity contracts
      Unrealized gain on derivative instruments, net       769        2,718  
Natural gas commodity contracts
      Realized gain (loss) on derivative instruments, net       24        (3,603 ) 
Crude oil commodity contracts
      Realized loss on derivative instruments, net       (590 )       (10,389 ) 
    
 
 
     
 
 
  
     $ 414      $ (12,074 ) 
    
 
 
     
 
 
  
 
12
(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,
  
    
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  
  
 
 
     
 
 
        
 
 
     
 
 
     
 
 
13

Table of Contents
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 Consolidated Financial Statements and the accompanying Notes to the 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 own producing and non-producing properties located primarily in Texas, and Oklahoma. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as 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 it has approximately $500,000 of working capital on its balance sheet. We believe our 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 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, exploration and 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.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities, and the operational performance of our producing properties. On occasion, we will use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. When used, our derivative contracts are accounted for under mark-to-market accounting and we can expect volatility in gains and losses on contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. Our most recent derivative instruments expired in March of 2023 and at this time we do not intend to enter into future derivative contracts unless required for our bank line of credit.

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

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

The Company is actively developing non-producing reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas, the Company maintains an acreage position of approximately 9,266 net acres, 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, we believe this acreage has significant resource potential in the Spraberry, Jo Mill, and Wolfcamp reservoirs for additional drilling that could support as many as 250 additional horizontal wells. In Oklahoma, our horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties where we have approximately 4,113 net acres with additional resource potential that could support the drilling of as many as 43 new horizontal wells based on an estimate of four wells per section: two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in such future development, our share of capital expenditures would be approximately $33 million at an average 10% ownership level.

 

14

Table of Contents

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

District Information

The following table represents certain reserves and well information as of December 31, 2022.

 

     Gulf
Coast		      Mid-
Continent		      West
Texas		      Other      Total  

Proved Reserves as of December 31, 2022 (MBoe)

               

Developed

      790        2,549        7,001        13        10,353  

Undeveloped

      —          110        6,256        —          6,366  

Total

      790        2,659        13,257        13        16,719  

Average Net Daily Production (Boe per day)

      227        897        3,257        4        4,385  

Gross Productive Wells (Working Interest and ORRI Wells)

      150        508        557        151        1,373  

Gross Productive Wells (Working Interest Only)

      132        383        511        82        1,108  

Net Productive Wells (Working Interest Only)

      69        169        254        6        498  

Gross Operated Productive Wells

      89        176        310        —          575  

Gross Operated Water Disposal, Injection and Supply wells

      7        40        6        —          53  

In our West Texas and Gulf Coast producing regions we have field service groups that service our operated wells and provide well-site services to third-party operators. These services are performed primarily utilizing workover or swab rigs, water transport trucks, hot-oil trucks, and saltwater disposal facilities that we own and that are operated by our field employees.

Gulf Coast Region

Our production activities in the Gulf Coast region are concentrated in east and southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox and Yegua formations at depths ranging from 5,000 to 11,000 feet. On December 31, 2022, we had 790 MBoe of proved reserves in the Gulf Coast region, which represented 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 8,707 gross (3,782 net) acres in this region, primarily in Polk County. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, water transport trucks, two commercial saltwater disposal wells, hot oil trucks, and plugging equipment. As of September 30, 2023, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed, and no other related activities of material importance.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2022, we had 508 producing wells (169 net) in the Mid-Continent area, of which 176 wells are operated by us. Principal producing intervals are in the Robberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. The average net daily production in our Mid-Continent Region in 2022 was 897 Boe. On December 31, 2022, we had 2,659 MBoe of proved reserves in this region, representing 16% of our total proved reserves. We currently maintain an acreage position of approximately 46,960 gross (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 interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily 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.

Year-to-date, in the Mid-Continent region, the Company has participated with 1.96% interest in the drilling and completion of three 3-mile-long horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc. All three wells were brought on production in June of this year. The expected reserves of these three wells were included in the 2022 year-end reserve report as proved undeveloped. The Company has added additional proved-producing reserves through various over-riding royalty interests in 12 horizontal wells, totaling 5.78% net revenue interest.

 

15

Table of Contents

West Texas Region

Our West Texas activities are concentrated in the Permian Basin where much of the United States’ oil reserves are produced from the prolific Wolfcamp and Spraberry reservoirs. The oil is West Texas Intermediate Sweet and the produced casing-head gas has a high BTU content making it the primary source of our natural gas liquids. The oil and gas are primarily from five producing intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2022, we had 557 wells (254 net) in the West Texas area, of which 310 wells are operated by us. The average net daily production in Our West Texas Region at year-end 2022 was 3,257 Boe. As of December 31, 2022, we had 13,256 MBoe of proved reserves in the West Texas area, or 79.3 % of our total proved reserves. We maintain an acreage position of approximately 16,171 gross (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, three hot oiler trucks, and one kill truck. Services, including well service support, site preparation, and construction services for drilling and workover operations, are provided to third-party operators as well as utilized in our own operated wells and locations.

In the first three quarters of 2023, the Company has added 22 completed horizontal wells to its West Texas proved-producing portfolio through our participation in 15 wells in Reagan County, five in Martin County, and two in Upton County. Ten of the 15 wells in Reagan County are operated by 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 has invested approximately $78 million in these 22 horizontals and owns an average 32.2% working interest.

In the fourth quarter of 2023, the Company is participating in an additional 18 horizontal wells operated by Double Eagle, located in our Hughes Alpine area of Reagan County (Studley Tracts): we are participating with 6.82% working interest in 6 two-mile-long horizontals that are expected to be on production in December of this year, and participating with 20% interest in 12 two and a half-mile-long laterals that are expected to be on production in February of 2024. In total, the Company is investing approximately $27 million in these 18 new horizontals and their associated facilities.    

As a result of the recent success of wells completed by Double Eagle and Civitas in Reagan County, as well as existing analogs and relatively high oil prices, both of these companies have accelerated their development plans in the area where we have significant leasehold acreage. Double Eagle and Civitas each have three rigs running in the area and in the fourth quarter of 2023, we expect to begin drilling an additional 20 wells with 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 activity described above, we expect another 12 wells, operated by Double Eagle, to begin drilling on adjacent or nearby acreage in the first quarter of 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 that are expected to begin production by February 2024, and preparing to invest $84 million in 14 wells with Civitas Resources and 20 wells with Double Eagle in Reagan County that are expected to begin drilling in the fourth quarter of 2023 and have production starts in the second quarter of 2024. In addition, we expect the drilling of 12 more horizontal wells to begin in the first quarter of 2024, carrying a net capital requirement of approximately $48 million. Therefore, the total capital commitment for wells to spud by the end of the first quarter of 2024 is approximately $159 million.

Reserves

Our interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2022. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and twenty-five years of

experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over thirty years of experience, holds a Bachelor’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:

 

16

Table of Contents

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 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, reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest. In our Gulf Coast Region, in 2020, we successfully recompleted one operated well in the Segno field of Polk County, Texas with a 72.5% interest.

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

In 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas, and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells. Also in 2021, the Company participated with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma. Twelve of these thirteen horizontal wells were 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 shut-in reserves attributable to three horizontals drilled and completed in Canadian County, Oklahoma, but not yet online at year-end. These reserves were converted to proved producing in the first quarter of 2022. At year-end 2021, we did not include proved-undeveloped reserves in our reserve report because we had not yet received definitive drilling proposals from third-party operators 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 third quarter of 2023.

 

17

Table of Contents

In the first quarter of 2023, 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 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 table below (in thousands of dollars) are the estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2022:

 

    Proved Developed     Proved Undeveloped      Total  

As of December 31,

   Future Net
Revenue		     Present
Value 10
Of Future
Net
Revenue		     Future Net
Revenue		     Present
Value 10
Of Future
Net
Revenue		      Future Net
Revenue		      Present
Value 10
Of Future
Net
Revenue		      Present
Value 10
Of Future
Income
Taxes		      Standardized
Measure of
Discounted
Cash flow		  
2020   $ 43,886     $ 34,717     $ 37,346     $ 21,823      $ 81,232      $ 56,539      $ 14,920      $ 41,619  
2021   $ 275,227     $ 171,906     $ —     $ —      $ 275,227      $ 171,906      $ 36,100      $ 135,806  
2022   $ 320,146     $ 192,688     $ 200,790     $ 118,081      $ 520,936      $ 310,769      $ 66,233      $ 244,536  

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

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

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

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

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $6.358 per MMBtu in 2022 as compared to $3.598 per MMBtu in 2021, and $1.985 per MMBtu in 2020. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month average spot price, were $93.67 per barrel in 2022 as compared to $66.56 per barrel in 2021, and $39.57 per barrel in 2020. Since January 1, 2022, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

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.

 

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Table of Contents

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2023, we 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.

We 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 18 wells in Reagan County, and an additional 34 wells anticipated to spud by year-end. The following is a description of recent, current, and expected near-term drilling activities.    Note, the drilling activities described below were previously described on a district basis in the District Information section above.

In the fourth quarter of 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 2.5-mile-long horizontal wells (Schenecker A Tract) with 20.83% interest, investing approximately $12.1 million, in Reagan County, we participated with Hibernia Energy III in 10 two-mile horizontals (Brynn Tract) with 25% interest, investing approximately $25.6 million, and, also in Reagan County, 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 put into production in 2023.

In the first quarter of 2023, the Company joined Ovintiv USA, Inc. in the drilling of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and invested approximately $645,000. Production of these three wells began in June. Also in the first quarter of 2023, the Company began participation with Apache Corporation in the drilling of two 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 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 three quarters of 2024. Our interest in these 35 wells will vary from 20% to 50% and we expect a capital outlay related to these wells and their facilities of approximately $143 million.    

All of the current and expected near-term activities described above encompass the 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 will require a net investment of approximately $100 million.

In summary, we have invested $78 million in 25 new horizontals this year that are 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 compared to $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. Current year net income reflects changes in production and commodity prices 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.

 

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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 Derivatives We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. The following table summarizes the results of our derivative instruments for 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 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

 

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Table of Contents

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 oil and gas revenues in 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 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 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 fluctuated during the three and nine months ended September 30, 2023 compared with the 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 $7.6 million for the third quarter 2022 to $8.9 million for the third quarter 2023 and increased $1.5 million, or 7.0% from $21.4 million for the nine months ended September 30, 2022 to $22.9 million for the nine months ended September 30, 2023. This increase reflects the expense related to the new wells placed on production in 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 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 net income.

LIQUIDITY AND CAPITAL RESOURCES

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2023, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2023 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures.

 

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Table of Contents

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, 2023 was $78.1 million, compared to $62.7 million in the prior 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. If the borrowing base utilization percentage is less than 15% of total available borrowings, the Company is not required to enter into any hedge agreements. The Company has no outstanding borrowings and all hedge agreements were settled or terminated prior to March 31, 2023. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $65 million. As of November 15, 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 2023. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.

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

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

 

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

 

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Table of Contents

PART II—OTHER INFORMATION

 

Item 1.

LEGAL PROCEEDINGS

None.

 

Item 1A.

RISK FACTORS

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

 

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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

 

2023 Month

    Number of
Shares		      Average Price
Paid per share		      Maximum
Number of Shares
that May Yet Be
Purchased Under
The Program at
Month—End (1)		  

January

      9,500      $ 90.36        45,044  

February

      3,000      $ 90.32        42,044  

March

      18,940      $ 85.44        23,104  

April

      10,560      $ 86.21        12,544  

May

      11,000      $ 86.69        1,544  

June

      7,500      $ 100.35        294,044  

July

      4,000      $ 94.00        290,044  

August

      4,000      $ 98.09        286,044  

September

      4,000      $ 109.73        282,044  
  

 

 

     

 

 

     

Total/Average

      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, June 13, 2018 and June 7, 2023, the Board of Directors of the Company approved an additional 500,000, 200,000 and 300,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 4,000,000 shares have been authorized to date under this program. Through September 30, 2023, a total of 3,717,956 shares have been repurchased under this program for $89,053,479 at an average price of $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

None

 

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Table of Contents
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)

 

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

PrimeEnergy Resources Corporation

 

(Registrant)

November 17, 2023

  

/s/ Charles E. Drimal, Jr.

(Date)

  

Charles E. Drimal, Jr.

 

President

 

Principal Executive Officer

 

/s/ Beverly A. Cummings

November 17, 2023

  

Beverly A. Cummings

 

Executive Vice President

 

Principal Financial Officer

 

25

EXHIBIT 31.1

CERTIFICATIONS

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

 

  1.

I have reviewed this Form 10-Q for the quarter ended September 30, 2023 of PrimeEnergy Resources Corporation;

 

  2.

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

 

  3.

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

 

  4.

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

 

  (a)

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

 

  (b)

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

 

  (c)

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

 

  (d)

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

 

  5.

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

 

  (a)

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

 

  (b)

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

November 17, 2023

 

/s/ Charles E. Drimal, Jr.
Charles E. Drimal, Jr.
Chief Executive Officer
PrimeEnergy Resources Corporation

EXHIBIT 31.2

CERTIFICATIONS

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

 

  1.

I have reviewed this Form 10-Q for the quarter ended September 30, 2023 of PrimeEnergy Resources Corporation;

 

  2.

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

 

  3.

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

 

  4.

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

 

  (a)

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

 

  (b)

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

 

  (c)

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

 

  (d)

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

 

  5.

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

 

  (a)

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

 

  (b)

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

November 17, 2023

 

/s/ Beverly A. Cummings
Beverly A. Cummings
Chief Financial Officer
PrimeEnergy Resources Corporation

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-Q for the period ending September 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles E. Drimal Jr., Chief Executive Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

 

  (1)

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

 

  (2)

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

 

/s/ Charles E. Drimal, Jr.

Charles E. Drimal, Jr.

Chief Executive Officer

November 17, 2023

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PrimeEnergy Resources Corporation (the “Company”) on Form 10-Q for the period ending September 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Resources Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

 

  (1)

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

 

  (2)

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

 

/s/ Beverly A. Cummings

Beverly A. Cummings

Chief Financial Officer

November 17, 2023
v3.23.3
Cover Page - shares
 9 Months Ended
Sep. 30, 2023
Nov. 13, 2023
Cover [Abstract]    
Document Type 10-Q  
Amendment Flag false  
Document Period End Date Sep. 30, 2023  
Document Fiscal Year Focus 2023  
Document Fiscal Period Focus Q3  
Entity Registrant Name PrimeEnergy Resources Corporation  
Entity Central Index Key 0000056868  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Shell Company false  
Entity Filer Category Non-accelerated Filer  
Entity Small Business true  
Entity Emerging Growth Company false  
Title of 12(b) Security Common Stock  
Trading Symbol PNRG  
Security Exchange Name NASDAQ  
Entity Common Stock, Shares Outstanding   1,820,576
Document Transition Report false  
Entity File Number 0-7406  
Entity Incorporation, State or Country Code DE  
Entity Address, Address Line One 9821 Katy Freeway  
Entity Address, City or Town Houston  
Entity Address, State or Province TX  
Entity Address, Postal Zip Code 77024  
City Area Code 713  
Local Phone Number 735-0000  
Entity Tax Identification Number 84-0637348  
Document Quarterly Report true  
v3.23.3
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Sep. 30, 2023
Dec. 31, 2022
Current assets:    
Cash and cash equivalents $ 19,790 $ 26,543
Accounts receivable, net 17,372 12,147
Prepaid obligations 413 32,839
Derivative asset 0 210
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 Property and Equipment, Net 215,101 173,987
Right-of-use assets 458 852
Other Assets 403 133
Total Assets 253,575 247,137
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
Derivative liability 0 1,190
Total current liabilities 41,684 40,957
Long-term bank debt 0 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
Related Party [Member]    
Current assets:    
Due from related parties 0 388
Current liabilities:    
Due to related parties $ 398 $ 0
v3.23.3
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares
Sep. 30, 2023
Dec. 31, 2022
Statement of Financial Position [Abstract]    
Common stock, par value $ 0.10 $ 0.10
Common stock, shares authorized 2,810,000 2,810,000
Common stock, shares outstanding 1,828,500 1,901,000
Treasury stock, shares 981,500 909,000
v3.23.3
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
 3 Months Ended 9 Months Ended
Sep. 30, 2023
Sep. 30, 2022
Sep. 30, 2023
Sep. 30, 2022
Revenues:        
Realized loss on derivative instruments, net $ 0 $ (4,285,000) $ (566,000) $ (13,992,000)
Unrealized gain on derivative instruments, net 0 6,124,000 980,000 1,918,000
Other income 0 0 38,000 29,000
Total revenues 35,360,000 39,314,000 87,617,000 100,738,000
Costs and expenses:        
Oil and gas production 7,898,000 6,476,000 21,171,000 20,888,000
Production and ad valorem taxes 1,445,000 2,201,000 5,308,000 5,721,000
Field service 3,166,000 2,670,000 9,700,000 8,725,000
Depreciation, depletion and amortization 8,924,000 7,569,000 22,857,000 21,386,000
Accretion of discount on asset retirement obligations 183,000 163,000 550,000 545,000
General and administrative 2,714,000 2,453,000 8,086,000 11,543,000
Total costs and expenses 24,330,000 21,532,000 67,672,000 68,808,000
Gain on sale and exchange of assets 2,102,000 494,000 8,206,000 15,330,000
Income from operations 13,132,000 18,276,000 28,151,000 47,260,000
Other income (expense)        
Interest expense (133,000) (253,000) (428,000) (752,000)
Interest income 113,000 8,000 286,000 8,000
Income before income taxes 13,112,000 18,031,000 28,009,000 46,516,000
Income tax provision 2,392,000 4,877,000 5,789,000 11,237,000
Net income $ 10,720,000 $ 13,154,000 $ 22,220,000 $ 35,279,000
Net income per share attributable to common stockholders: Basic $ 5.84 $ 6.79 $ 11.95 $ 17.95
Net income per share attributable to common stockholders: 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
Weighted average shares outstanding: Diluted 2,593,924 2,694,906 2,617,758 2,722,522
Oil Sales [Member]        
Revenues:        
Oil, gas and service income $ 26,402,000 $ 23,403,000 $ 61,948,000 $ 75,546,000
Natural gas [Member]        
Revenues:        
Oil, gas and service income 2,472,000 6,359,000 5,452,000 14,762,000
Natural gas liquids [Member]        
Revenues:        
Oil, gas and service income 3,149,000 4,204,000 8,323,000 12,477,000
Field service [Member]        
Revenues:        
Oil, gas and service income $ 3,337,000 $ 3,509,000 $ 11,442 $ 9,998,000
v3.23.3
CONSOLIDATED STATEMENT OF EQUITY - USD ($)
$ in Thousands
Total
Common Stock [Member]
Additional Paid-In Capital [Member]
Retained Earnings [Member]
Treasury Stock [Member]
Total Stockholders' Equity – PrimeEnergy [Member]
Shares Outstanding [Member]
Balance at Dec. 31, 2021   $ 281 $ 7,555 $ 128,902 $ (37,647) $ 99,091  
Balance, shares at Dec. 31, 2021             1,992,077
Purchase of treasury stock         (833) 833  
Purchase of treasury stock, shares             (11,188)
Net Income       11,142   11,142  
Balance at Mar. 31, 2022   281 7,555 140,044 (38,480) 109,400  
Balance, shares at Mar. 31, 2022             1,980,889
Balance at Dec. 31, 2021   281 7,555 128,902 (37,647) 99,091  
Balance, shares at Dec. 31, 2021             1,992,077
Net Income $ 35,279            
Balance at Sep. 30, 2022   281 7,555 164,181 (42,639) 129,378  
Balance, shares at Sep. 30, 2022             1,930,700
Balance at Mar. 31, 2022   281 7,555 140,044 (38,480) 109,400  
Balance, shares at Mar. 31, 2022             1,980,889
Purchase of treasury stock         (2,354) (2,354)  
Purchase of treasury stock, shares             (28,244)
Net Income       10,983   10,983  
Balance at Jun. 30, 2022   281 7,555 151,027 (40,834) 118,029  
Balance, shares at Jun. 30, 2022             1,952,645
Purchase of treasury stock         (1,805) (1,805)  
Purchase of treasury stock, shares             (21,945)
Net Income 13,154     13,154   13,154  
Balance at Sep. 30, 2022   281 7,555 164,181 (42,639) 129,378  
Balance, shares at Sep. 30, 2022             1,930,700
Balance at Dec. 31, 2022   281 7,555 177,566 (45,049) 140,353  
Balance, shares at Dec. 31, 2022             1,901,000
Purchase of treasury stock         (2,748) (2,748)  
Purchase of treasury stock, shares             (31,440)
Net Income       1,410   1,410  
Balance at Mar. 31, 2023   281 7,555 178,976 (47,797) 139,015  
Balance, shares at Mar. 31, 2023             1,869,560
Balance at Dec. 31, 2022   281 7,555 177,566 (45,049) 140,353  
Balance, shares at Dec. 31, 2022             1,901,000
Net Income 22,220            
Balance at Sep. 30, 2023   281 7,555 199,786 (51,621) 156,001  
Balance, shares at Sep. 30, 2023             1,828,500
Balance at Mar. 31, 2023   281 7,555 178,976 (47,797) 139,015  
Balance, shares at Mar. 31, 2023             1,869,560
Purchase of treasury stock         (2,616) (2,616)  
Purchase of treasury stock, shares             (29,060)
Net Income       10,090   10,090  
Balance at Jun. 30, 2023   281 7,555 189,066 (50,413) 146,489  
Balance, shares at Jun. 30, 2023             1,840,500
Purchase of treasury stock         (1,208) (1,208)  
Purchase of treasury stock, shares             (12,000)
Net Income $ 10,720     10,720   10,720  
Balance at Sep. 30, 2023   $ 281 $ 7,555 $ 199,786 $ (51,621) $ 156,001  
Balance, shares at Sep. 30, 2023             1,828,500
v3.23.3
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 9 Months Ended
Sep. 30, 2023
Sep. 30, 2022
Cash Flows from Operating Activities:    
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 (5,225) (2,735)
Due from related parties 388 0
Due to related parties 398 61
Prepaids obligations 32,426 (308)
Accounts payable 449 (1,114)
Accrued liabilities 2,700 2,705
Other, net (173) 0
Net Cash Provided by Operating Activities 70,724 47,346
Cash Flows from Investing Activities:    
Capital expenditures, including exploration expense (67,069) (7,972)
Proceeds from sale of properties and equipment 7,434 15,330
Net Cash Provided by (Used in) Investing Activities (59,635) 7,358
Cash Flows from Financing Activities:    
Purchase of stock for treasury (6,572) (4,992)
Repayment of long-term bank debt and other long-term obligations (11,270) (36,000)
Net Cash Used in Financing Activities (17,842) (40,992)
Net (Decrease) Increase in Cash and Cash Equivalents (6,753) 13,712
Cash and Cash Equivalents at the Beginning of the Period 26,543 10,347
Cash and Cash Equivalents at the End of the Period 19,790 24,059
Supplemental Disclosures:    
Income taxes paid 9,288 61
Interest paid $ 450 $ 714
v3.23.3
Basis of Presentation
 9 Months Ended
Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Basis of Presentation
(1) Basis of Presentation:
The accompanying consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form
10-K
for the year ended December 31, 2022. In the opinion of management, the accompanying interim consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s consolidated balance sheets as of September 30, 2023, and December 31, 2022, the consolidated results of operations, cash flows and equity for the nine months ended September 30, 2023, and 2022.
As of September 30, 2023, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form
10-K
for the fiscal year ended December 31, 2022. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.
v3.23.3
Acquisitions and Dispositions
 9 Months Ended
Sep. 30, 2023
Business Combinations [Abstract]  
Acquisitions and Dispositions
(2) Acquisitions and Dispositions
2023 Transactions
:
In the first quarter of 2023, the Company sold 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.
In the second quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320
non-core
acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.
In the third quarter of 2023, the Company sold a
non-core
38.25-acre
leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original ownership in such wells. In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres.
In November 2023, the Company sold 136 surface acres in Oklahoma for proceeds of $306,000.
2022 Transactions
:
In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.0 million.
In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for $845,000.
In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.
v3.23.3
Additional Balance Sheet Information
 9 Months Ended
Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Additional Balance Sheet Information
(3) Additional Balance Sheet Information:
Certain balance sheet amounts are comprised of the following:
 
(Thousands of dollars)
   
September 30,
2023
     
December 31,
2022
  
Accounts Receivable:
      
Joint interest billing
    $ 1,931      $ 1,806  
Trade receivables
      2,193        1,762  
Oil and gas sales
      13,523        8,894  
Other
      63        21  
  
 
 
     
 
 
  
     17,710      12,483  
 
(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  
  
 
 
     
 
 
  
 
(Thousands of dollars)
   
September 30,
2023
     
December 31,
2022
  
Accrued Liabilities:
      
Compensation and related expenses
    $ 4,837      $ 9,743  
Property costs
      17,889        4,718  
Taxes
      3,024        9,352  
Operating costs
      2,322        1,695  
Other
      378        242  
  
 
 
     
 
 
  
Total
    $ 28,450      $ 25,750  
  
 
 
     
 
 
  
v3.23.3
Long-Term Debt
 9 Months Ended
Sep. 30, 2023
Debt Disclosure [Abstract]  
Long-Term Debt
(4) Long-Term Debt:
Bank Debt:
The Company maintains a revolving corporate credit facility (the “Credit Facility”) with a group of financial institutions with aggregate loan commitments of $300 million, subject to a borrowing base that is determined semi-annually, with a maturity date of June 1, 2026. As of December 31, 2022, the borrowing base was $75 million and the Company had $11 million outstanding borrowings under the Credit Facility.
The Credit Facility requires the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, and places restrictions on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements. As of June 30, 2023, the Company was in compliance with its debt covenants. Borrowings bear interest, at the option of the Company, based on a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) Adjusted Term SOFR (secured overnight financing rate as administered by the Federal Reserve Bank of New York) for a
one-month
tenor in effect on such day plus 1.00%, or a Term SOFR. Both options are subject to an additional margin, determined based upon the utilization of the borrowing base then in effect, ranging from 2.25% to 4.25% per annum. The Company also pays commitment fees on undrawn amounts under the Credit Facility of 0.50% per annum. Borrowings under the Credit Facility are secured by substantially all of the Company’s oil and gas properties.
Effective January 20, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and Prime of the 2022 Credit Agreement resulted in an adjustment to decrease the amount of the Borrowing Base available from $75 million to $60 million until such time as the next redetermination date as required by the agreement.
Effective July 24, 2023 the borrowing base was increased to $65 million. The borrowing base as of September 30, 2023 remained at $65 million and the Company hand no outstanding borrowings under the Credit Facility at that time.
As of November 15, 2023 the Company had no outstanding borrowings under the Credit Facility.
v3.23.3
Other Long-Term Obligations and Commitments
 9 Months Ended
Sep. 30, 2023
Debt Disclosure [Abstract]  
Other Long-Term Obligations and Commitments
(5) Other Long-Term Obligations and Commitments:
Operating Leases:
The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the
 
lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 7.82%. Certain leases may contain variable costs above the minimum required payments and are not included in the
right-of-use
assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet.
Operating lease costs for the nine months ended September 30, 2023 and 2022 were $525,000 and $468,000, respectively. Cash payments included in the operating lease cost for the nine months ended September 30, 2023 and 2022 were $552,000 and $499,000, respectively. The weighted-average remaining operating lease terms as of September 30, 2023 and 2022 were 7.88 months and 6.33 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for payments of $187,000 in 2023, $275,000 in 2024 and $45,000 in 2025.
Rent expense for office space for the nine months ended September 30, 2023 and 2022 was $555,000 and $563,000, respectively.
The payment schedule for the Company’s operating lease obligations as of September 30, 2023 is as follows:
 
(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  
  
 
 
  
Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2023 is as follows:
 
(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  
  
 
 
  
The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.
 
v3.23.3
Contingent Liabilities
 9 Months Ended
Sep. 30, 2023
Commitments and Contingencies Disclosure [Abstract]  
Contingent Liabilities
(6) Contingent Liabilities:
The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
v3.23.3
Stock Options and Other Compensation
 9 Months Ended
Sep. 30, 2023
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]  
Stock Options and Other Compensation
(7) Stock Options and Other Compensation:
In May 1989,
non-statutory
stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 30, 2023 and 2022, the remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.
v3.23.3
Related Party Transactions
 9 Months Ended
Sep. 30, 2023
Related Party Transactions [Abstract]  
Related Party Transactions
(8) Related Party Transactions:
Amounts due to or from related parties primarily represent receipts or expenses, related to oil and gas properties, collected or paid by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors.
v3.23.3
Financial Instruments
 9 Months Ended
Sep. 30, 2023
Fair Value Disclosures [Abstract]  
Financial Instruments
(9) Financial Instruments
Fair Value Measurements:
Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at September 30, 2023 and December 31, 2022:
 
September 30, 2023
   
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,
2023
  
(Thousands of dollars)
                            
Assets
            
Commodity derivative contracts
    $ —      $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Total assets
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Liabilities
            
Commodity derivative contracts
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Total liabilities
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
 
December 31, 2022
   
Quoted Prices in
Active Markets
For Identical
Assets (Level 1)
     
Significant
Other
Observable
Inputs (Level 2)
     
Significant
Unobservable
Inputs (Level 3)
     
Balance at
December 31,
2022
  
(Thousands of dollars)
                            
Assets
            
Commodity derivative contracts
    $ —        $ —        $ 210      $ 210  
  
 
 
     
 
 
     
 
 
     
 
 
  
Total assets
    $ —        $ —        $ 210      $ 210  
  
 
 
     
 
 
     
 
 
     
 
 
  
Liabilities
            
Commodity derivative contracts
    $ —        $ —        $ (1,190 )     $ (1,190 ) 
  
 
 
     
 
 
     
 
 
     
 
 
  
Total liabilities
    $ —        $ —        $ (1,190 )     $ (1,190 ) 
  
 
 
     
 
 
     
 
 
     
 
 
  
The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.
The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.
 
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2023.
 
(Thousands of dollars)
       
Net Liabilities – December 31, 2022
    $ (980 ) 
Total realized and unrealized gains (losses):
   
Included in earnings (a)
      414  
Purchases, sales, issuances and settlements
      566  
  
 
 
  
Net Liabilities — 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.
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, 2023 and December 31, 2022:
 
           
Fair Value
  
(Thousands of dollars)
   
Balance Sheet Location
     
September 30,
2023
     
December 31,
2022
  
Asset Derivatives:
         
Derivatives not designated as cash-flow hedging instruments:
         
Crude oil commodity contract
      Derivative asset      $ —        $ 162  
Natural gas commodity contract
      Derivative asset        —          48  
     
 
 
     
 
 
  
Total
       $ —        $ 210  
     
 
 
     
 
 
  
Liability Derivatives:
         
Derivatives not designated as cash-flow hedging instruments:
         
Crude oil commodity contracts
      Derivative liability      $ —        $ (931 ) 
Natural gas commodity contracts
      Derivative liability        —          (259 ) 
     
 
 
     
 
 
  
Total
       $ —        $ (1,190 ) 
     
 
 
     
 
 
  
Total derivative instruments
       $ —        $ (980 ) 
     
 
 
     
 
 
  
The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine months ended September 30, 2023 and 2022:
 
          
Amount of gain (loss)

recognized in in o me
  
(Thousands of dollars)
   
Location of gain/loss recognized in income
    
2023
     
2022
  
Derivatives not designated as cash-flow hedge instruments:
        
Natural gas commodity contracts
      Unrealized gain (loss) on derivative instruments, net       211        (800 ) 
Crude oil commodity contracts
      Unrealized gain on derivative instruments, net       769        2,718  
Natural gas commodity contracts
      Realized gain (loss) on derivative instruments, net       24        (3,603 ) 
Crude oil commodity contracts
      Realized loss on derivative instruments, net       (590 )       (10,389 ) 
    
 
 
     
 
 
  
     $ 414      $ (12,074 ) 
    
 
 
     
 
 
  
v3.23.3
Earnings per Share
 9 Months Ended
Sep. 30, 2023
Earnings Per Share [Abstract]  
Earnings per Share
(10) Earnings Per Share:
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:
 
    
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  
  
 
 
     
 
 
        
 
 
     
 
 
     
v3.23.3
Additional Balance Sheet Information (Tables)
 9 Months Ended
Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Components of Balance Sheet Amounts
Certain balance sheet amounts are comprised of the following:
 
(Thousands of dollars)
   
September 30,
2023
     
December 31,
2022
  
Accounts Receivable:
      
Joint interest billing
    $ 1,931      $ 1,806  
Trade receivables
      2,193        1,762  
Oil and gas sales
      13,523        8,894  
Other
      63        21  
  
 
 
     
 
 
  
     17,710      12,483  
 
(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  
  
 
 
     
 
 
  
 
(Thousands of dollars)
   
September 30,
2023
     
December 31,
2022
  
Accrued Liabilities:
      
Compensation and related expenses
    $ 4,837      $ 9,743  
Property costs
      17,889        4,718  
Taxes
      3,024        9,352  
Operating costs
      2,322        1,695  
Other
      378        242  
  
 
 
     
 
 
  
Total
    $ 28,450      $ 25,750  
  
 
 
     
 
 
  
v3.23.3
Other Long-Term Obligations and Commitments (Tables)
 9 Months Ended
Sep. 30, 2023
Debt Disclosure [Abstract]  
Summary of Operating and Financing Lease Obligation
The payment schedule for the Company’s operating lease obligations as of September 30, 2023 is as follows:
 
(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  
  
 
 
  
Reconciliation of Liability for Plugging and Abandonment Costs
A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2023 is as follows:
 
(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  
  
 
 
  
v3.23.3
Financial Instruments (Tables)
 9 Months Ended
Sep. 30, 2023
Fair Value Disclosures [Abstract]  
Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at September 30, 2023 and December 31, 2022:
 
September 30, 2023
   
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,
2023
  
(Thousands of dollars)
                            
Assets
            
Commodity derivative contracts
    $ —      $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Total assets
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Liabilities
            
Commodity derivative contracts
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
Total liabilities
    $ —        $ —        $ —        $ —    
  
 
 
     
 
 
     
 
 
     
 
 
  
 
December 31, 2022
   
Quoted Prices in
Active Markets
For Identical
Assets (Level 1)
     
Significant
Other
Observable
Inputs (Level 2)
     
Significant
Unobservable
Inputs (Level 3)
     
Balance at
December 31,
2022
  
(Thousands of dollars)
                            
Assets
            
Commodity derivative contracts
    $ —        $ —        $ 210      $ 210  
  
 
 
     
 
 
     
 
 
     
 
 
  
Total assets
    $ —        $ —        $ 210      $ 210  
  
 
 
     
 
 
     
 
 
     
 
 
  
Liabilities
            
Commodity derivative contracts
    $ —        $ —        $ (1,190 )     $ (1,190 ) 
  
 
 
     
 
 
     
 
 
     
 
 
  
Total liabilities
    $ —        $ —        $ (1,190 )     $ (1,190 ) 
  
 
 
     
 
 
     
 
 
     
 
 
  
Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2023.
 
(Thousands of dollars)
       
Net Liabilities – December 31, 2022
    $ (980 ) 
Total realized and unrealized gains (losses):
   
Included in earnings (a)
      414  
Purchases, sales, issuances and settlements
      566  
  
 
 
  
Net Liabilities — 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.
Effect of Derivative Instruments on Consolidated Balance Sheets
The following table sets forth the effect of derivative instruments on the consolidated balance sheets at September 30, 2023 and December 31, 2022:
 
           
Fair Value
  
(Thousands of dollars)
   
Balance Sheet Location
     
September 30,
2023
     
December 31,
2022
  
Asset Derivatives:
         
Derivatives not designated as cash-flow hedging instruments:
         
Crude oil commodity contract
      Derivative asset      $ —        $ 162  
Natural gas commodity contract
      Derivative asset        —          48  
     
 
 
     
 
 
  
Total
       $ —        $ 210  
     
 
 
     
 
 
  
Liability Derivatives:
         
Derivatives not designated as cash-flow hedging instruments:
         
Crude oil commodity contracts
      Derivative liability      $ —        $ (931 ) 
Natural gas commodity contracts
      Derivative liability        —          (259 ) 
     
 
 
     
 
 
  
Total
       $ —        $ (1,190 ) 
     
 
 
     
 
 
  
Total derivative instruments
       $ —        $ (980 ) 
     
 
 
     
 
 
  
Effect of Derivative Instruments on Consolidated Statements of Operations
The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine months ended September 30, 2023 and 2022:
 
          
Amount of gain (loss)

recognized in in o me
  
(Thousands of dollars)
   
Location of gain/loss recognized in income
    
2023
     
2022
  
Derivatives not designated as cash-flow hedge instruments:
        
Natural gas commodity contracts
      Unrealized gain (loss) on derivative instruments, net       211        (800 ) 
Crude oil commodity contracts
      Unrealized gain on derivative instruments, net       769        2,718  
Natural gas commodity contracts
      Realized gain (loss) on derivative instruments, net       24        (3,603 ) 
Crude oil commodity contracts
      Realized loss on derivative instruments, net       (590 )       (10,389 ) 
    
 
 
     
 
 
  
     $ 414      $ (12,074 ) 
    
 
 
     
 
 
  
v3.23.3
Earnings per Share (Tables)
 9 Months Ended
Sep. 30, 2023
Earnings Per Share [Abstract]  
Computation of Basic and Diluted Earnings (Loss) per Share The following reconciles amounts reported in the financial statements:
 
    
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  
  
 
 
     
 
 
        
 
 
     
 
 
     
v3.23.3
Acquisitions and Dispositions - Additional Information (Detail)
 3 Months Ended
Nov. 30, 2023
USD ($)
a
Jul. 01, 2023
USD ($)
a
Sep. 30, 2023
USD ($)
a
Jun. 30, 2023
USD ($)
a
Mar. 31, 2023
USD ($)
a
Sep. 30, 2022
USD ($)
a
Jun. 30, 2022
USD ($)
a
Mar. 31, 2022
USD ($)
a
Business Acquisition [Line Items]                
Number of acres sold | a 136   3          
Proceeds from Divestiture of Businesses     $ 37,053,000          
Percentage of ownership in divestiture of businesses   50.00%            
OKLAHOMA [Member]                
Business Acquisition [Line Items]                
Proceeds from Divestiture of Businesses $ 306,000,000         $ 423,700,000 $ 845,000,000  
Consideration Transferred, Liabilities Incurred     $ 1,500,000          
TEXAS [Member]                
Business Acquisition [Line Items]                
Number of Area of Land | a   114.52   55        
Cash Acquired from Acquisition   $ 1,700,853,000            
Number of acres sold | a     38.25 320 7.8     1,809
Proceeds from Divestiture of Businesses     $ 899,000 $ 60,000,000 $ 436,050     $ 14,000,000
Gain (Loss) on Disposition of Business         $ 47,000      
Payment to acquire land held for use       605,000        
Proceeds from the sale of land held for use       $ 6,000,000        
Percentage of interest in divestiture of businesses       36.51%        
CANADA [Member]                
Business Acquisition [Line Items]                
Number of acres sold | a           113 241  
v3.23.3
Additional Balance Sheet Information - Components of Balance Sheet Amounts (Detail) - USD ($)
$ in Thousands
Sep. 30, 2023
Dec. 31, 2022
Accounts Receivable:    
Joint interest billings $ 1,931 $ 1,806
Trade receivables 2,193 1,762
Oil and gas sales 13,523 8,894
Other 63 21
Accounts Receivable, Gross 17,710 12,483
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
Accrued Liabilities:    
Compensation and related expenses 4,837 9,743
Property costs 17,889 4,718
Taxes 3,024 9,352
Operating costs 2,322 1,695
Other 378 242
Total $ 28,450 $ 25,750
v3.23.3
Long-Term Debt - Additional Information (Detail) - USD ($)
$ in Thousands
 9 Months Ended
Jan. 20, 2023
Sep. 30, 2023
Nov. 15, 2023
Jul. 24, 2023
Dec. 31, 2022
Maximum [Member]          
Debt Instrument [Line Items]          
Debt Instrument, Basis Spread on Variable Rate   4.25%      
Maximum [Member] | 2022 Credit Agreement [Member]          
Debt Instrument [Line Items]          
Decrease in Borrowing Base $ 75,000        
Minimum [Member]          
Debt Instrument [Line Items]          
Debt Instrument, Basis Spread on Variable Rate   2.25%      
Minimum [Member] | 2022 Credit Agreement [Member]          
Debt Instrument [Line Items]          
Decrease in Borrowing Base $ 60,000        
Revolving Credit Facility [Member]          
Debt Instrument [Line Items]          
Credit facility borrowing capacity   $ 300,000      
Line of credit facility, expiration date   Jun. 01, 2026      
Long-term Line of Credit   $ 0     $ 11,000
Debt Instrument, Face Amount   $ 65,000   $ 65,000 $ 75,000
Debt Instrument, Basis Spread on Variable Rate   0.50%      
Revolving Credit Facility [Member] | Subsequent Event [Member]          
Debt Instrument [Line Items]          
Long-term Line of Credit     $ 0    
Fed Funds Effective Rate Overnight Index Swap Rate [Member]          
Debt Instrument [Line Items]          
Debt Instrument, Basis Spread on Variable Rate   0.50%      
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate [Member]          
Debt Instrument [Line Items]          
Debt Instrument, Basis Spread on Variable Rate   1.00%      
v3.23.3
Other Long-Term Obligations and Commitments - Additional Information (Detail) - USD ($)
 9 Months Ended
Sep. 30, 2023
Sep. 30, 2022
Weighted-average discount rate 7.82%  
Operating lease weighted-average remaining lease term 7 months 26 days 6 months 10 days
Operating lease payments $ 552,000 $ 499,000
Operating lease cost $ 525,000 468,000
Lease period description The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term.  
Rent Expenses $ 555,000 $ 563,000
Lease Payments Due Next year 187,000  
Lease payments due next two years 275,000  
Lease payments due next third years $ 45,000  
v3.23.3
Other Long-Term Obligations and Commitments - Summary of Operating and Financing Lease Obligation (Detail)
Sep. 30, 2023
USD ($)
2023 $ 187,000
2024 275,000
2025 45,000
Total undiscounted lease payments 507,000
Less: Amount associated with discounting (49,000)
Total net operating lease liabilities 458,000
Less: Current portion included in current portion of asset retirement and other long-term obligations 381,000
Non-current portion included in other long-term obligations $ 77,000
Operating Lease, Liability, Statement of Financial Position [Extensible Enumeration] Total net operating lease liabilities
v3.23.3
Other Long-Term Obligations and Commitments - Reconciliation of Liability for Plugging and Abandonment Costs (Detail) - USD ($)
$ in Thousands
 3 Months Ended 9 Months Ended
Sep. 30, 2023
Sep. 30, 2022
Sep. 30, 2023
Sep. 30, 2022
Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]          
Asset retirement obligation     $ 15,443    
Additions     16    
Dispositions     (1,161)    
Liabilities settled     (2,727)    
Accretion of discount $ 183 $ 163 550 $ 545  
Asset retirement obligation 12,121   12,121    
Less current portion of asset retirement obligations 554   554    
Asset retirement obligations, long-term $ 11,567   $ 11,567   $ 13,525
v3.23.3
Stock Options and Other Compensation - Additional Information (Detail)
Sep. 30, 2023
shares
Dec. 31, 2022
$ / shares
shares
May 31, 1989
Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Options outstanding, shares | shares 767,500 767,500  
Number of key executive officers to whom non-statutory stock options granted | Officers     4
Minimum [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Average exercise price | $ / shares   $ 1  
Maximum [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Average exercise price | $ / shares   $ 1.25  
Nonstatutory Stock Options [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Options exercisable, shares | shares 767,500 767,500  
v3.23.3
Financial Instruments - Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($)
$ in Thousands
Sep. 30, 2023
Dec. 31, 2022
Assets    
Derivative assets $ 0 $ 210
Liabilities    
Derivative liabilities 0 (1,190)
Fair Value, Measurements, Recurring [Member]    
Assets    
Derivative assets 0 210
Liabilities    
Derivative liabilities 0 (1,190)
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]    
Assets    
Derivative assets 0 210
Liabilities    
Derivative liabilities 0 (1,190)
Significant Unobservable Inputs (Level 3) [Member] | Fair Value, Measurements, Recurring [Member]    
Assets    
Derivative assets 0 210
Liabilities    
Derivative liabilities 0 (1,190)
Significant Unobservable Inputs (Level 3) [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]    
Assets    
Derivative assets 0 210
Liabilities    
Derivative liabilities $ 0 $ (1,190)
v3.23.3
Financial Instruments - Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3 (Detail)
$ in Thousands
 9 Months Ended
Sep. 30, 2023
USD ($)
Total realized and unrealized (gains) losses:  
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] Revenues
Significant Unobservable Inputs (Level 3) [Member]  
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]  
Net Liabilities at beginning of period $ (980)
Total realized and unrealized (gains) losses:  
Included in earnings 414 [1]
Purchases, sales, issuances and settlements 566
Net Liabilities end of period $ 0
[1] Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments.
v3.23.3
Financial Instruments - Effect of Derivative Instruments on Consolidated Balance Sheets (Detail) - USD ($)
$ in Thousands
Sep. 30, 2023
Dec. 31, 2022
Derivatives, Fair Value [Line Items]    
Derivative assets $ 0 $ 210
Derivative liabilities 0 (1,190)
Total derivative instruments 0 (980)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Derivative asset [Member]    
Derivatives, Fair Value [Line Items]    
Derivative assets 0 48
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Derivative liability [Member]    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 0 (259)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Derivative asset [Member]    
Derivatives, Fair Value [Line Items]    
Derivative assets 0 162
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Derivative liability [Member]    
Derivatives, Fair Value [Line Items]    
Derivative liabilities $ 0 $ (931)
v3.23.3
Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Detail) - USD ($)
$ in Thousands
 9 Months Ended
Sep. 30, 2023
Sep. 30, 2022
Derivative Instruments, Gain (Loss) [Line Items]    
Amount of gain/loss recognized in income $ 414 $ (12,074)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] Revenues Revenues
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Unrealized gain (loss) on derivative instruments, net [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Amount of gain/loss recognized in income $ 211 $ (800)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Realized gain (loss) on derivative instruments, net [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Amount of gain/loss recognized in income 24 (3,603)
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Unrealized gain (loss) on derivative instruments, net [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Amount of gain/loss recognized in income 769 2,718
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Realized loss on derivative instruments, net [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Amount of gain/loss recognized in income $ (590) $ (10,389)
v3.23.3
Earnings per Share - Computation of Basic and Diluted Earnings (Loss) Per Share (Detail) - USD ($)
$ / shares in Units, $ in Thousands
 3 Months Ended 9 Months Ended
Sep. 30, 2023
Sep. 30, 2022
Sep. 30, 2023
Sep. 30, 2022
Earnings Per Share [Abstract]        
Net Income, Basic $ 10,720 $ 13,154 $ 22,220 $ 35,279
Net Income, Diluted $ 10,720 $ 13,154 $ 22,220 $ 35,279
Weighted Average Number of Shares Outstanding, Basic 1,834,709 1,937,091 1,859,084 1,965,334
Weighted Average Number of Shares Outstanding, Options 759,214 757,815 758,674 757,218
Weighted Average Number of Shares Outstanding, Diluted 2,593,924 2,694,906 2,617,758 2,722,522
Per Share Amount, Basic $ 5.84 $ 6.79 $ 11.95 $ 17.95
Per Share Amount, Diluted $ 4.13 $ 4.88 $ 8.49 $ 12.96
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