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Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited)
 12 Months Ended
Dec. 31, 2023
Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) [Abstract]  
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED)

NOTE 13 — SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED)

 

The Company has only one reportable operating segment, which is oil and natural gas development, exploration, and production in the United States. See the Company’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities.

 

Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities

 

Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated depreciation, depletion, and amortization are presented below as of the dates indicated:

 

   As of December 31, 
   2023   2022 
Oil and natural gas properties  Successor   Predecessor 
         
Proved  $94,189,372   $64,799,213 
Less: accumulated depreciation, depletion, and amortization   (352,127)   (9,592,296)
Net oil and natural gas properties capitalized costs  $93,837,245   $55,206,917 

 

Costs Incurred for Oil and Natural Gas Producing Activities

 

Costs incurred in crude oil and natural gas exploration and development for the periods presented: 

 

   Successor   Predecessor 
   November 15, 2023 to
December 31,
2023		   January 1,
2023 to
November 14,
2023		   For the
year ended
December 31,
2022		 
Exploration costs  $
-
   $
-
   $1,031,300 
Development costs   238,499    6,769,557    15,048,100 
Total  $238,499   $6,769,557   $16,079,400 

 

Reserve Quantity Information

 

The following information represents estimates of the Company’s proved reserves as of December 31, 2023 and 2022, which have been prepared by an independent third party and they are presented in accordance with SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2023 and 2022 was based on an unweighted average 12-month average U.S. Energy Information Administration WTI posted price per Bbl for oil and Henry Hub prices for natural gas price per Mcf for natural gas, adjusted for transportation, quality and basis differentials.

 

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more. The Company’s proved oil and natural gas reserves are located in the United States in the Permian Basin of southeast New Mexico. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB. Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

 

The following table and subsequent narrative disclosure provides a roll forward of the total proved reserves for the years ended December 31, 2023 and 2022 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

 

   For the years ended December 31, 
   2023       2022 
   Oil
(MBbls)		   Natural
Gas
(MMcf)		   Total
(MBoe)		   Oil
(MBbls)		   Natural
Gas
(MMcf)		   Total
(MBoe)		 
Proved Reserves:                        
Beginning of period   17,577    4,572    18,339    17,868    3,714    18,487 
Extensions and discoveries   1,817    277    1,863    
—
    
—
    
—
 
Dispositions   (1,758)   (457)   (1,834)   
—
    
—
    
—
 
Revisions to previous estimates   (1,758)   (729)   (1,995)   106    1,315    325 
Production   (349)   (356)   (409)   (397)   (457)   (473)
End of period   15,414    3,307    15,965    17,577    4,572    18,339 
Proved Developed Reserves:                              
Beginning of period   13,014    3,572    13,609    13,161    2,875    13,640 
End of period   11,277    2,456    11,686    13,014    3,572    13,609 
Proved Undeveloped Reserves:                              
Beginning of period   4,564    1,000    4,730    4,707    839    4,847 
End of period   4,137    850    4,279    4,564    1,000    4,730 

 

Extensions and discoveries. For the year ended December 31, 2023 and 2022, extensions and discoveries contributed to the increase of 1,863 MBoe and 0 MBoe, respectively, in the Company’s proved reserves. The increase of extensions and discoveries in 2023 is due to the Company’s development of the Seven Rivers waterflood.

 

Dispositions: For the year ended December 31, 2023, dispositions represent the removal of reserves attributed to the sale of an undivided royalty interest equal in amount to ten percent (10%) by the Predecessor to Pogo Royalty of the Predecessor’s all oil, gas and minerals in, under and produced from each lease.

 

Revisions of previous estimates. For the year ended December 31, 2023, revisions of previous estimates resulted in the decrease of reserves with a negative revision of 1,995 MBoe in the Company’s proved reserves. The negative revision in 2023 is primarily attributable to the decrease in year-end SEC commodity prices for oil and natural gas.

 

For the year ended December 31, 2022, revisions of previous estimates partially offset the decrease in reserves with a positive revision of 325 MBoe in the Company’s proved reserves. The positive revision in 2022 is primarily attributable to the increase in year-end SEC commodity prices for oil and natural gas.

 

Standardized Measure of Discounted Future Net Cash Flows

 

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of a property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions.

 

The estimates of future cash flows and future production and development costs as of December 31, 2023 and 2022 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

 

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

 

   For the year ended
December 31,		 
   2023   2023 
   Successor   Predecessor 
   (in thousands) 
Future cash inflows  $1,216,840   $1,680,514 
Future production costs   (438,653)   (451,155)
Future development costs   (94,156)   (124,216)
Future net cash flows   684,031    1,105,143 
10% annual discount for estimated timing of cash flows   (403,413)   (585,596)
Standardized measure of discounted future net cash flows  $280,618   $519,547 

 

In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2023 and 2022 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. Furthermore, future development costs include abandonment costs.

 

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.

 

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

 

   For the year ended
December 31,		 
   2023   2022 
   (in thousands) 
Balance, beginning of period (Predecessor)  $519,547   $307,409 
Net change in sales and transfer prices and in production (lifting) costs related to future production   (95,981)   176,448 
Sales and transfers of oil and natural gas produced during the period   (22,914)   (23,501)
Changes in estimated future development costs   (2,313)   12,926)
Previously estimated development incurred during the period   7,008    2,100 
Net purchases (divestitures) of reserves in place   (138,893)   
—
 
Net change due to revisions in quantity estimates   (45,534)   9,217 
Net change due to extensions and discoveries, and improved recovery   
—
    
—
 
Accretion of discount   51,955    30,741 
Timing and other differences   7,742    4,207 
Standardized measure of discounted future net cash flows (Successor for 2023, Predecessor for 2022)  $280,618   $519,547