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Note 17 - Supplemental Crude Oil and Natural Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2023

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

NOTE 17 – Supplemental Crude Oil and Natural Gas Disclosures (Unaudited)

The Company only has one reportable operating segment, which is crude oil and natural gas development, exploration and production in the U.S.

Net Capitalized Costs

The following table reflects the capitalized costs of crude oil and natural gas properties and the related accumulated depletion (in thousands):

	December 31,
	2023			2022
Proved properties	$	3,338,107		$	2,270,236
Unproved properties		72,715			114,665
Total capitalized costs		3,410,822			2,384,901
Less: accumulated depletion		(684,179	)		(259,962	)
Net capitalized costs	$	2,726,643		$	2,124,939

Cost Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development

The following table reflects costs incurred in crude oil and natural gas property acquisition, development and exploratory activities (in thousands):

	Year Ended December 31,
	2023		2022		2021
Acquisition costs:
Proved properties	$	3,308	$	352,791	$	33,253
Unproved properties		11,777		174,554		20,792
Total acquisition costs		15,085		527,345		54,045
Exploration costs		527,502		655,433		190,346
Development costs		481,528		391,298		45,852
Crude oil and natural gas expenditures		1,024,115		1,574,076		290,243
Asset retirement obligations, net		6,048		2,879		1,844
Total costs incurred	$	1,030,163	$	1,576,955	$	292,087

Results of Operations for Crude Oil, NGL and Natural Gas Producing Activities

The following table reflects the Company’s results of operations for crude oil, NGL and natural gas producing activities (in thousands):

	Year Ended December 31,
	2023		2022		2021
Crude oil, NGL and natural gas sales	$	1,111,293	$	755,686	$	220,124
Lease operating expenses		145,362		69,599		25,053
Production and ad valorem taxes		58,472		38,440		10,746
Exploration and abandonment expense		5,234		1,149		1,549
Depletion, depreciation and amortization expense		424,424		177,742		65,201
Accretion of discount on asset retirement obligations		522		370		167
Income tax expense		100,229		98,361		24,656
Results of operations from crude oil and natural gas production activities	$	377,050	$	370,025	$	92,752

Crude Oil, NGL and Natural Gas Reserves

Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month spot prices prior to the end of the reporting period. These prices as of December 31, 2023, 2022 and 2021 were $78.22, $93.67 and $66.56 per barrel for crude oil and NGL and $2.637, $6.358 and $3.598 per MMBtu for natural gas, respectively. The estimated realized prices used in computing the Company’s reserves as of December 31, 2023 were as follows: (i) $78.13 per barrel of crude oil, (ii) $17.33 per barrel of NGL, and (iii) $0.198 per Mcf of natural gas. The estimated realized prices used in computing the Company’s reserves as of December 31, 2022 were as follows: (i) $94.59 per barrel of crude oil, (ii) $36.69 per barrel of NGL, and (iii) $4.871 per Mcf of natural gas. The estimated realized prices used in computing the Company’s reserves as of December 31, 2021 were as follows: (i) $66.10 per barrel of crude oil, (ii) $29.76 per barrel of NGL, and (iii) $0.786 per Mcf of natural gas. All prices are net of adjustments for regional basis differentials, treating costs, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity adjustments.

The proved reserve estimates as of December 31, 2023, 2022 and 2021 were prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), independent reserve engineers, and reflect the Company’s current development plans. All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond the Company’s control, such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of that estimate.

Reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. Estimating quantities of proved crude oil and natural gas reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as crude oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company’s reserve estimates are inherently imprecise.

The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from crude oil and natural gas properties the Company owns declines as reserves are depleted. Except to the extent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the Company’s proved reserves will decline as reserves are produced.

The following table reflects changes in proved reserves during the periods indicated:

	Crude Oil (MBbl)			NGL (MBbl)			Natural Gas (MMcf)			Total (MBoe)
Proved Reserves on December 31, 2020		19,032			2,160			7,939			22,515
Extensions and discoveries		36,867			4,845			19,529			44,967
Purchase of reserves-in-place		973			631			2,910			2,089
Sales of minerals-in-place		(238	)		(44	)		(139	)		(305	)
Revisions of previous estimates		(1,807	)		10			842			(1,657	)
Production		(3,002	)		(224	)		(1,020	)		(3,396	)
Proved Reserves on December 31, 2021		51,825			7,378			30,061			64,213
Extensions and discoveries		47,677			6,162			24,887			57,987
Purchase of reserves-in-place		13,031			3,467			14,448			18,906
Revisions of previous estimates		(6,155	)		(1,817	)		(7,435	)		(9,211	)
Production		(7,562	)		(821	)		(3,323	)		(8,937	)
Proved Reserves on December 31, 2022		98,816			14,369			58,638			122,958
Extensions and discoveries		54,137			6,456			27,330			65,148
Purchase of reserves-in-place		89			47			208			171
Sales of reserves-in-place		(1,171	)		(127	)		(531	)		(1,387	)
Revisions of previous estimates		(18,432	)		898			8,644			(16,093	)
Production		(13,885	)		(1,547	)		(7,218	)		(16,635	)
Proved Reserves on December 31, 2023		119,554			20,096			87,071			154,162

On December 31, 2023, the Company had approximately 154,162 MBoe of proved reserves. For the year ended December 31, 2023, extensions and discoveries increased proved reserves by 65,148 MBoe as a result of; (i) drilling 63 gross (56.4 net) exploratory/extension wells that were on production as of December 31, 2023, (ii) 7 gross (6.6 net) exploratory/extension wells that were in the final stages of completion as of December 31, 2023, and (iii) the addition of 117 gross (102.4 net) PUDs. The Company also acquired 171 MBoe of reserves as part of its acquisition activities and divested of 1,387 MBoe of reserves in a farm out to another operator in return for a carried interest during the year ended December 31, 2023. Downward revisions of previous estimates of 16,093 MBoe for the year ended December 31, 2023 were the result of negative revisions of approximately 13,729 MBoe primarily due to technical revisions attributable to decreased well performance and adjustments to our estimates, approximately 1,775 MBoe primarily related to decreases in crude oil, NGL and natural gas realized prices and approximately 589 MBoe primarily due to increased forecasted operating expenses. The aforementioned net increase in proved reserves was partially offset by 16,635 MBoe in production during the year ended December 31, 2023. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return.

On December 31, 2022, the Company had approximately 122,958 MBoe of proved reserves. For the year ended December 31, 2022, extensions and discoveries increased proved reserves by 57,987 MBoe as a result of: (i) drilling 37 gross (32.1 net) exploratory/extension wells that were on production as of December 31, 2022, (ii) 16 gross (14.8 net) exploratory/extension wells that were in the final stages of completion as of December 31, 2022, and (iii) the addition of 80 gross (75.2 net) PUDs. The Company also acquired 18,906 MBoe of reserves as part of its acquisition activities during the year ended December 31, 2022. Downward revisions of previous estimates of 9,211 MBoe for the year ended December 31, 2022 were primarily the result of negative revisions of 10,418 MBoe due to technical revisions attributable to decreased well performance and adjustments to our PUD estimates, partially offset by positive revisions of approximately 1,116 MBoe related to increases in crude oil, NGL and natural gas realized prices and positive revisions of approximately 91 MBoe primarily due to increased forecasted operating expenses. The aforementioned net increase in proved reserves was partially offset by 8,937 MBoe in production during the year ended December 31, 2022. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return.

On December 31, 2021, the Company had approximately 64,213 MBoe of proved reserves. For the year ended December 31, 2021, extensions and discoveries increased proved reserves by 44,967 MBoe as a result of: (i) drilling 22 gross (17.8 net) exploratory wells that were on production as of December 31, 2021, (ii) 15 gross (11.0 net) exploratory wells that were in the final stages of completion as of December 31, 2021, and (iii) the addition of 53 gross (41.5 net) PUDs. The Company also acquired 2,089 MBoe of reserves as part of its acquisition activities and sold assets with proved reserves totaling 305 MBoe during the year ended December 31, 2021 in an acreage trade with an industry partner. Downward revisions of previous estimates of 1,657 MBoe for the year ended December 31, 2021 were primarily the result of: (i) negative revisions of 2,529 MBoe due to technical revisions attributable to decreased well performance and adjustments to our PUD estimates, (ii) negative revisions of approximately 85 MBoe primarily due to increased forecasted operating expenses and (iii) partially offset by positive revisions of approximately 957 MBoe related to increases in crude oil, NGL and natural gas realized prices. The aforementioned net increase in proved reserves was partially offset by 3,396 MBoe in production during the year ended December 31, 2021. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return.

The following table sets forth the Company’s estimated quantities of proved developed and proved undeveloped crude oil, NGL and natural gas reserves:

	December 31,
	2023		2022		2021
Proved Developed Reserves (1)
Crude oil (MBbl)		58,631		47,845		22,610
NGL (MBbl)		12,183		7,968		3,540
Natural gas (MMcf)		52,671		32,669		14,611
Total (MBoe)		79,593		61,258		28,585
Proved Undeveloped Reserves
Crude oil (MBbl)		60,923		50,971		29,215
NGL (MBbl)		7,913		6,401		3,838
Natural gas (MMcf)		34,400		25,969		15,450
Total (MBoe)		74,569		61,700		35,628
Total Proved Reserves
Crude oil (MBbl)		119,554		98,816		51,825
NGL (MBbl)		20,096		14,369		7,378
Natural gas (MMcf)		87,071		58,638		30,061
Total (MBoe)		154,162		122,958		64,213

(1)

As of December 31, 2023, 2022 and 2021 and 2020, proved developed reserves includes proved developed non-producing reserves of 4,598, 7,417, 6,884 and 4,517 MBbl of crude oil, 534, 927, 793 and 517 MBbl of NGL and 1,889, 3,641, 3,222 and 1,912 MMcf of natural gas, respectively.

On December 31, 2023, the Company’s estimated PUD reserves were approximately 74,569 MBoe, a 12,869 MBoe increase over the reserve estimate at December 31, 2022 of 61,700 MBoe. The following table includes the changes in PUD reserves for 2023 (in MBoe):

Beginning proved undeveloped reserves on December 31, 2022	61,700
Undeveloped reserves transferred to proved developed reserves	(25,955	)
Extensions and discoveries	42,440
Sales of reserves-in-place	(1,387	)
Revisions	(2,229	)
Ending proved undeveloped reserves on December 31, 2023	74,569

Standardized Measure of Discounted Future Net Cash Flows

The following table reflects the Company’s standardized measure of discounted future net cash flows relating from its proved crude oil, natural gas and NGL reserves (in thousands):

	December 31,
	2023			2022			2021
Future cash inflows	$	9,706,290		$	10,159,310		$	3,668,535
Future production costs		(2,869,377	)		(2,289,852	)		(824,865	)
Future development costs (1)		(1,568,033	)		(983,732	)		(432,370	)
Future income tax expense		(680,894	)		(1,102,156	)		(431,737	)
Future net cash flows		4,587,986			5,783,570			1,979,563
Discount to present value at 10% annual rate		(1,980,282	)		(2,367,062	)		(860,754	)
Standardized measure of discounted future net cash flows (1)	$	2,607,704		$	3,416,508		$	1,118,809

The following table reflects the principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves (in thousands):

	Year Ended December 31,
	2023			2022			2021
Standardized measure of discounted future net cash flows, beginning of year	$	3,416,508		$	1,118,809		$	222,192
Sales of crude oil and natural gas, net of production costs		(907,459	)		(647,647	)		(184,325	)
Extensions and discoveries, net of future development costs (1)		1,202,674			1,785,822			987,689
Net changes in prices and production costs		(1,404,147	)		909,053			272,889
Changes in estimated future development costs (1)		(37,820	)		(23,647	)		(13,551	)
Purchases of minerals-in-place		4,344			499,478			31,353
Sales of reserves-in-place		(25,069	)		—			(3,067	)
Revisions of previous quantity estimates		(390,282	)		(354,868	)		(40,466	)
Accretion of discount		395,656			134,338			23,419
Net changes in income taxes		266,579			(315,478	)		(212,574	)
Net changes in timing of production and other		86,720			310,648			35,250
Standardized measure of discounted future net cash flows, end of year (1)	$	2,607,704		$	3,416,508		$	1,118,809

(1)

The standardized measure of discounted future net cash flows reflects, within the category for future development costs, all estimated future costs that will be incurred to settle our asset retirement obligations, including costs for dismantlement, restoration, and abandonment of the existing wells (including both active and inactive wells on leases and future proved undeveloped locations), in each case in compliance with FASB ASC 932-235-50-36.