Annual report pursuant to Section 13 and 15(d)

SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

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SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
12 Months Ended
Dec. 31, 2022
Extractive Industries [Abstract]  
SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

NOTE 15. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

 

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development

 

Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new ARO established in the current year, as well as increases or decreases to the ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

 

In 2020, the Company purchased 50% working interest in the Utikuma field in Alberta, Canada for an aggregate purchase price of $678,765. In connection with the acquisition, Company recognized an asset retirement obligation of $906,146. An additional $1,000,000 CAD was contingent on the future price of WTI crude. At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021. The additional payments due were netted with the accounts receivable balance from previous Joint Interest Billing statements from BSR. The total $USD value of the addition was $787,250, using prevailing exchange rates on the respective dates.

 

   

Fiscal Year Ended

December 31, 2022

   

Fiscal Year Ended

December 31, 2021

 
Property acquisitions   $     $ 787,250  
Unevaluated            
Evaluated            
Exploration            
Development            
Total costs incurred   $     $ 787,250  

 

Capitalized costs

 

Capitalized costs include the cost of properties, equipment and facilities for oil and natural-gas producing activities, excluding any asset retirement obligations. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds and geological and geophysical expenses where no proved reserves have been identified.

 

    December 31, 2022     December 31, 2021  
Capitalized costs:                
Unevaluated properties   $     $  
Evaluated properties     5,414,771       5,511,480  
Gross capitalized costs     5,414,771       5,511,480  
Less: Accumulated DD&A     -651,754       (448,960 )
Net capitalized costs   $

4,763,017

    $ 5,062,520  

 

 

Oil and Gas Reserve Information

 

MKM Engineering (“MKM”), an independent engineering firm, prepared the estimates of the proved reserves, future production, and income attributable to the Chaves County, New Mexico and Creek County, Oklahoma and Canadian property leasehold interests as of December 31, 2022 and the estimates of the proved reserves, future production, and income attributable to the Milam County, Texas, Chaves County, New Mexico and Creek County, Oklahoma leasehold interests as of December 31, 2021. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Company’s Proved Reserves are located onshore in the continental United States of America and Canada.

 

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

 

The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated.

 

    BOE  
December 31, 2020     1,311,672  
Revisions of prior estimates     292,335  
Purchases of reserves in place      
Disposition of mineral in place     (57,070 )
Production     (97,084 )
December 31, 2021     1,449,853  
Revisions of prior estimates     (232,950 )
Purchases of reserves in place      
Disposition of mineral in place     (71,380 )
Production   (80,333 )
December 31, 2022     1,065,190  

 

    December 31, 2022     December 31, 2021  
             
Estimated quantities of proved developed reserves – BOE     1,043,830       1,449,853  
Estimated quantities of proved undeveloped reserves – BOE     21,360        

 

Proved developed and proved undeveloped reserves decreased from December 31, 2021 to December 31, 2022, primarily due the revision of prior estimates and production, and the removal of all Twin Lakes reserves.

 

The following table sets forth estimates of the proved developed and proved undeveloped oil and gas reserves (net of royalty interests) for the Company and changes therein, for the period indicates.

 

Proved developed producing and non-producing reserve   BOE  
December 31, 2021     1,449,853  
Revision of prior estimates     (325,690 )
Production     (80,334 )
December 31, 2022     1,043,830  

 

 

Proved undeveloped reserves   BOE  
December 31, 2021      
Revisions to prior estimates     21,360  
December 31, 2022     21,360  

 

Standardized Measure of Discounted Future Net Cash Flows

 

The Standardized Measure related to proved oil and gas reserves is summarized below. Future cash inflows were computed by applying a twelve-month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company.

 

Standardized Measure of Oil and Gas

 

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated.

 

    December 31, 2022     December 31, 2021  
             
Future cash inflows   $ 95,454,352     $ 93,082,624  
Future production costs     (49,218,382 )     (45,892,778 )
Future development costs     (2,622,876 )     (1,867,485 )
Future income taxes            
                 
Future net cash flows     43,613,094       45,322,361  
Discount of future net cash flows at 10% per annum```     (20,782,000 )     (27,929,984 )
                 
Standardized measure of discounted future net cash flows   $ 22,831,094     $ 17,392,377  

 

Changes in standardized measure of discounted future cash flows

 

    December 31, 2022     December 31, 2021  
             
Beginning of year   $ 17,392,377     $ 7,956,920  
Sales and transfers of oil & gas produced, net of production costs     (660,629 )     (539,927 )
Net changes in prices and production costs     (1,278,130 )     (865,805 )
Changes in estimated future development costs     537,696     (565,870 )
Acquisitions/dispositions of minerals in place, net of production costs     (367,027 )     (231,470 )
Revision of previous estimates     (11,820,528 )     1,194,016
Change in discount            
Change in production rate or other     19,027,334       10,444,513
                 
End of year   $ 22,831,094     $ 17,392,377