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Note 18 - Supplemental Crude Oil and Natural Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2022

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

NOTE 18 – 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. See the Company’s accompanying consolidated statements of operations for information about results of operations for crude oil and natural gas producing activities.

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,
	2022			2021
Proved properties	$	2,270,236		$	699,701
Unproved properties		114,665			108,392
Total capitalized costs		2,384,901			808,093
Less: accumulated depletion		(259,962	)		(82,478	)
Net capitalized costs	$	2,124,939		$	725,615

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,				August 22, 2020 through December 31,			January 1, 2020 through August 21,
	2022		2021		2020			2020
	Successor							Predecessor
Acquisition costs:
Proved properties	$	352,791	$	33,253	$	—		$	585
Unproved properties		174,554		20,792		1,181			2,753
Total acquisition costs		527,345		54,045		1,181			3,338
Exploration costs		655,433		190,346		52,837			48,801
Development costs		391,298		45,852		11,757			863
Crude oil and natural gas expenditures		1,574,076		290,243		65,775			53,002
Asset retirement obligations, net		2,879		1,844		(105	)		98
Total costs incurred	$	1,576,955	$	292,087	$	65,670		$	53,100

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,				August 22, 2020 through December 31,			January 1, 2020 through August 21,
	2022		2021		2020			2020
	Successor							Predecessor
Crude oil, NGL and natural gas sales	$	755,686	$	220,124	$	16,400		$	8,223
Lease operating expenses		69,599		25,053		2,653			4,870
Production and ad valorem taxes		38,440		10,746		886			566
Exploration and abandonment expense		1,149		1,549		5,032			4
Depletion, depreciation and amortization expense		177,742		65,201		9,877			6,385
Accretion of discount on asset retirement obligations		370		167		51			89
Income tax expense (benefit)		98,361		24,656		(441	)		—
Results of operations from crude oil and natural gas production activities	$	370,025	$	92,752	$	(1,658	)	$	(3,691	)

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, 2022, 2021 and 2020 were $93.67, $66.56 and $39.57 per barrel for crude oil and $6.358, $3.598 and $1.985 per MMBtu for natural gas, respectively. 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. The estimated realized prices used in computing the Company’s reserves as of December 31, 2020 were as follows: (i) $38.08 per barrel of crude oil, (ii) $12.27 per barrel of NGL, and (iii) ($1.304) 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, 2022, 2021 and 2020 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			NGL			Natural Gas			Total
*Predecessor*
Proved Reserves on December 31, 2019		9,372			1,349			4,654			11,497
Purchase of reserves-in-place		44			—			36			50
Extensions and discoveries		1,008			67			252			1,117
Revisions of previous estimates		(1,555	)		(374	)		(1,144	)		(2,120	)
Production		(236	)		(20	)		(87	)		(270	)
Proved Reserves on August 21, 2020		8,633			1,022			3,711			10,274

*Successor*
Proved Reserves on August 22, 2020		8,633			1,022			3,711			10,274
Extensions and discoveries		11,977			1,433			5,215			14,279
Revisions of previous estimates		(1,180	)		(277	)		(875	)		(1,603	)
Production		(398	)		(18	)		(112	)		(435	)
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

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.

On December 31, 2020, the Company had approximately 22,515 MBoe of proved reserves. Effective August 21, 2020, the HighPeak business combination included estimated proved reserves totaling 10,274 MBoe. For the period from August 22, 2020 to December 31, 2020, extensions and discoveries increased proved reserves by 14,279 MBoe as a result of: (i) drilling 3 gross (3.0 net) exploratory wells that were on production as of December 31, 2020, (ii) 9 gross (8.9 net) exploratory wells that were in the final stages of completion as of December 31, 2020, and (iii) the addition of 15 gross (12.4 net) PUDs. Downward revisions of previous estimates of 1,603 MBoe for the period from August 22, 2020 to December 31, 2020 were primarily the result of: (i) negative revisions of 1,112 MBoe due to technical revisions attributable to decreased well performance and adjustments to our PUD estimates, (ii) negative revisions of 409 MBoe related to PUDs removed from the development program, (iii) negative revisions of approximately 98 MBoe primarily due to decreases in crude oil, NGL and natural gas prices and increased price differentials and (iv) partially offset by positive revisions of approximately 16 MBoe related to decreased forecasted operating expenses. The net increase in proved reserves was partially offset by 435 MBoe in production during the period from August 22, 2020 to December 31, 2020.

On August 21, 2020, the Company had approximately 10,274 MBoe of proved reserves. During the period from December 31, 2019 to August 21, 2020, the Company acquired interests in three (3) producing vertical wells near its area of operation which included estimated proved reserves totaling 50 MBoe. For the period from December 31, 2019 to August 21, 2020, extensions and discoveries increased proved reserves by 1,117 MBoe as a result of: (i) drilling 3 gross (3.0 net) exploratory wells that were on production as of August 21, 2020. Revisions of previous estimates of 2,120 MBoe for the period from December 31, 2019 to August 21, 2020 were primarily the result of: (i) negative revisions totaling approximately 1,975 MBoe due to technical revisions attributable to decreased well performance of offset horizontal wells resulting in lessoned projected performance, (ii) negative revisions of approximately 173 MBoe primarily due to decreases in crude oil, NGL and natural gas prices and increased price differentials, and (iii) partially offset by positive revisions of 28 MBoe due to decreased forecasted operating expenses. Adding to the net decrease in proved reserves was 270 MBoe in production during the period from December 31, 2019 to August 21, 2020.

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,
	2022		2021		2020		2019
	Successor						Predecessor
Proved Developed Reserves (1)
Crude oil (MBbl)		47,845		22,610		8,730		4,091
NGL (MBbl)		7,968		3,540		957		548
Natural gas (MMcf)		32,669		14,611		3,572		1,952
Total (MBoe)		61,258		28,585		10,282		4,964
Proved Undeveloped Reserves
Crude oil (MBbl)		50,971		29,215		10,302		5,281
NGL (MBbl)		6,401		3,838		1,203		801
Natural gas (MMcf)		25,969		15,450		4,367		2,702
Total (MBoe)		61,700		35,628		12,233		6,533
Total Proved Reserves
Crude oil (MBbl)		98,816		51,825		19,032		9,372
NGL (MBbl)		14,369		7,378		2,160		1,349
Natural gas (MMcf)		58,638		30,061		7,939		4,654
Total (MBoe)		122,958		64,213		22,515		11,497

(1)

As of December 31, 2022, 2021, 2020 and 2019, proved developed reserves includes proved developed non-producing reserves of 7,417, 6,884, 4,517 and 3,101 MBbl of crude oil, 927, 793, 517 and 447 MBbl of NGL and 3,641, 3,222, 1,912 and 1,454 MMcf of natural gas, respectively.

On December 31, 2022, the Company’s estimated PUD reserves were approximately 61,700 MBoe, a 26,072 MBoe increase over the reserve estimate at December 31, 2020 of 35,628 MBoe. The following table includes the changes in PUD reserves for 2022 (in MBoe):

Beginning proved undeveloped reserves on December 31, 2021	35,628
Undeveloped reserves transferred to proved developed	(15,446	)
Revisions	(3,178	)
Purchase of reserves-in-place	7,302
Extensions and discoveries	37,394
Ending proved undeveloped reserves on December 31, 2022	61,700

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,
	2022			2021			2020
Future cash inflows	$	10,159,310		$	3,668,535		$	740,859
Future production costs		(2,289,852	)		(824,865	)		(217,025	)
Future development costs (3)		(983,732	)		(432,370	)		(117,887	)
Future income tax expense		(1,102,156	)		(431,737	)		(25,824	)
Future net cash flows		5,783,570			1,979,563			380,123
Discount to present value at 10% annual rate		(2,367,062	)		(860,754	)		(157,931	)
Standardized measure of discounted future net cash flows (3)	$	3,416,508		$	1,118,809		$	222,192

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,
	2022			2021			2020		(2)
Standardized measure of discounted future net cash flows, beginning of year	$	1,118,809		$	222,192		$	140,021
Sales of crude oil and natural gas, net of production costs		(647,647	)		(184,325	)		(15,648	)
Extensions and discoveries, net of future development costs (3)		1,785,822			987,689			172,478
Net changes in prices and production costs		909,053			272,889			(50,728	)
Changes in estimated future development costs (3)		(23,647	)		(13,551	)		6,466
Purchases of minerals-in-place		499,478			31,353			600
Sales of reserves-in-place		—			(3,067	)		—
Revisions of previous quantity estimates		(354,868	)		(40,466	)		(41,646	)
Accretion of discount		134,338			23,419			14,134
Net changes in income taxes (1)		(315,478	)		(212,574	)		(10,675	)
Net changes in timing of production and other		310,648			35,250			7,190
Standardized measure of discounted future net cash flows, end of year (3)	$	3,416,508		$	1,118,809		$	222,192

(1)

Effective with the HighPeak business combination that closed on August 21, 2020, the crude oil and natural gas properties became owned by HighPeak Energy, which is treated as a corporation for U.S. federal income tax purposes. As such, the “Net change in income taxes” in the table above for the year ended December 31, 2020 reflects the change in tax status applicable to the operations of the crude oil and natural gas properties. Prior to the HighPeak business combination, the Predecessor was treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses relating to the operation of the crude oil and natural gas properties were reported on the income tax returns of the Predecessor’s partners. The Predecessor was subject to margin / franchise taxes in Texas, which is reflected as “Net change in income taxes” in the table above.

(2)

The year ended December 31, 2020 in the table above reflects the change in standardized measure from that of HPK LP, our Predecessor, as of December 31, 2019 to that of the Company as of December 31, 2020 and amounts are combined for the period from January 1, 2020 to August 21, 2020 of HPK LP and from August 22, 2020 to December 31, 2020 of the Company. There was no third-party reserve report prepared as of August 21, 2020 from which to compute a standardized measure from as of that date. We believe the table above accurately reflects the change in standardized measure for the Predecessor and Successor in a meaningful context.

(3)

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.