Note 17 - Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

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

Note 17 – Supplemental Oil and Gas Disclosures (Unaudited)

Net Capitalized Costs

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

	Successor			Predecessors
	December 31, 2020			December 31, 2019
	(in thousands)
Proved properties	$	367,372		$	178,835
Unproved properties		152,741			227,525
Total capitalized costs		520,113			406,360
Less: accumulated depletion		(17,477	)		(1,566	)
Net capitalized costs	$	502,636		$	404,794

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

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

	Year Ended December 31, 2020
	Successor			Predecessors
	August 22, 2020 through December 31, 2020			January 1, 2020 through August 21, 2020		Year Ended December 31, 2019
Acquisition costs:
Proved properties	$	-		$	585	$	4,635
Unproved properties		1,181			2,753		6,288
Total acquisition costs		1,181			3,338		10,923
Exploration costs		52,837			48,801		59,349
Development costs		11,757			863		54
Oil and gas expenditures		65,775			53,002		70,326
Asset retirement obligations, net		(105	)		98		316
Total costs incurred	$	65,670		$	53,100	$	70,642

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

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

	Year Ended December 31, 2020
	Successor			Predecessors
	August 22, 2020 through December 31, 2020			January 1, 2020 through August 21, 2020			Year Ended December 31, 2019
Oil, NGL and natural gas sales	$	16,400		$	8,223		$	8,115
Lease operating expenses		2,653			4,870			3,372
Production and ad valorem taxes		886			566			449
Exploration and abandonment expense		5,032			4			2,850
Depletion, depreciation and amortization expense		9,877			6,385			4,269
Accretion of discount on asset retirement obligations		51			89			72
Results of operations from oil and gas production activities	$	(2,099	)	$	(3,691	)	$	(2,897	)

Oil, Natural Gas and NGL 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, 2020 and 2019 were $39.57 and $55.69 per barrel for crude oil and $1.985 and $2.578 per MMBtu for natural gas, respectively. The estimated realized prices used in computing the Company’s reserves as of December 31, 2020 were as follows: (i) oil - $38.08 per barrel, (ii) natural gas - ($1.304) per Mcf, and (iii) NGL - $12.27 per barrel. The estimated realized prices used in computing the Partnership’s reserves as of December 31, 2019 were as follows: (i) oil - $50.57 per barrel, (ii) natural gas - $0.10 per Mcf, and (iii) NGL - $21.17 per barrel. All prices are net of adjustments for regional basis differentials, treating costs, transportation, gas shrinkage, gas heating vale (BTU content) and/or crude quality and gravity adjustments.

The proved reserve estimates as of December 31, 2020 and 2019 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 oil and natural gas that are ultimately recovered. Estimating quantities of proved 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 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 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)			Natural Gas (MMcf)			NGL (MBbl)			Total (MBoe)
Predecessors
Proved Reserves at January 1, 2019		2,914			809			222			3,271
Contribution from HighPeak II		973			569			78			1,146
Extensions and discoveries		5,413			2,528			759			6,593
Revisions of previous estimates		217			887			290			655
Production		(145	)		(139	)		-			(168	)
Proved Reserves at December 31, 2019		9,372			4,654			1,349			11,497
Purchase of minerals in place		44			36			-			50
Extensions and discoveries		1,008			252			67			1,117
Revisions of previous estimates		(1,555	)		(1,144	)		(374	)		(2,120	)
Production		(236	)		(87	)		(20	)		(270	)
Proved Reserves at August 21, 2020		8,633			3,711			1,022			10,274
Successor
Proved Reserves at August 22, 2020		8,633			3,711			1,022			10,274
Extensions and discoveries		11,977			5,215			1,433			14,279
Revisions of previous estimates		(1,180	)		(875	)		(277	)		(1,603	)
Production		(398	)		(112	)		(18	)		(435	)
Proved Reserves at December 31, 2020		19,032			7,939			2,160			22,515

At 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 oil, natural gas and NGL prices and increased price differentials, (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. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return.

At August 21, 2020, the Company had approximately 10,274 MBoe of proved reserves. During the period from January 1, 2020 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 January 1, 2020 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 January 1, 2020 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 and adjustments to PUD estimates, (ii) negative revisions of approximately 173 MBoe primarily due to decreases in oil, natural gas and NGL 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 January 1, 20202 to August 21, 2020.

At December 31, 2019, the Predecessors had approximately 11,497 MBoe of proved reserves. Effective October 1, 2019, the contribution of a subsidiary to the Predecessors by HighPeak II included estimated proved reserves totaling 1,146 MBoe. For the year ended December 31, 2019, extensions and discoveries increased proved reserves by 6,593 MBoe as a result of: (i) drilling or participating in the drilling of 2 gross (1.8 net) exploratory wells that were on production as of December 31, 2019, (ii) 5 gross (5.0 net) exploratory wells that were being drilled or pending completion as of December 31, 2019, and (iii) the addition of 13 gross (4.4 net) PUDs. Revisions of previous estimates of 655 MBoe for the year ended December 31, 2019 were primarily the result of: (i) negative revisions totaling approximately 80 MBoe due to reductions in pricing and increases in pricing differentials, (ii) negative revisions of approximately 54 MBoe primarily due to increased forecasted operating expenses, and (iii) positive revisions of 789 MBoe due to improvements in well performance attributable to improved well performance of offset horizontal wells resulting in improved projected performance of these PUDs. The net increase in proved reserves was offset by 168 MBoe in production during the year ended December 31, 2019.

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

	Successor December 31, 2020		Predecessors December 31, 2019
Proved Developed Reserves (1)
Oil (MBbl)		8,730		4,091
Natural gas (MMcf)		3,572		1,952
Natural gas liquids (MBbl)		957		548
Total (MBoe)		10,282		4,964
Proved Undeveloped Reserves
Oil (MBbl)		10,302		5,281
Natural gas (MMcf)		4,367		2,702
Natural gas liquids (MBbl)		1,203		801
Total (MBoe)		12,233		6,533
Total Proved Reserves
Oil (MBbl)		19,032		9,372
Natural gas (MMcf)		7,939		4,654
Natural gas liquids (MBbl)		2,160		1,349
Total (MBoe)		22,515		11,497

⁽¹⁾ As of December 31, 2020 and 2019, proved developed reserves includes proved developed non-producing reserves of 4,517 and 3,101 MBbl of crude oil, 1,912 and 1,454 MMcf of natural gas and 517 and 447 MBbl of natural gas liquids, respectively.

Standardized Measure of Discounted Future Net Cash Flows

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

	Successor December 31, 2020			Predecessors December 31, 2019
Future cash inflows	$	740,859		$	502,961
Future production costs		(217,025	)		(127,897	)
Future development costs		(117,887	)		(78,360	)
Future income tax expense		(25,824	)		(2,640	)
Future net cash flows		380,123			294,064
Discount to present value at 10% annual rate		(157,931	)		(154,043	)
Standardized measure of discounted future net cash flows	$	222,192		$	140,021

⁽¹⁾  Effective beginning on August 22, 2020 and as of December 31, 2020, the Company is treated as a corporation for U.S. federal income tax purposes. Accordingly, “future income tax expense” above includes estimates of future federal income taxes and margin / franchise taxes in Texas that may be incurred by the Company. As of December 31, 2019, the Predecessors were each treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses were reported on the income tax returns of the Predecessor’s partners. The Predecessors were subject to margin / franchise taxes in Texas, which is reflected as “Future income tax expense”.

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

	Year Ended December 31, 2020 (2)			Year Ended December 31, 2019 (2)
Standardized measure of discounted future net cash flows, beginning of year	$	140,021		$	31,118
Contribution of HighPeak II to Predecessors		-			10,488
Sales of oil and natural gas, net of production costs		(15,648	)		(4,294	)
Extensions and discoveries, net of future development costs		172,478			85,626
Net changes in prices and production costs		(50,728	)		(6,755	)
Changes in estimated future development costs		6,466			9,483
Purchases of minerals in place		600			14
Revisions of previous quantity estimates		(41,646	)		8,232
Accretion of discount		14,134			3,165
Net changes in income taxes (1)		(10,675	)		(857	)
Net changes in timing of production and other		7,190			3,801
Standardized measure of discounted future net cash flows, end of year	$	222,192		$	140,021

⁽¹⁾  Effective with the HighPeak business combination that closed on August 21, 2020, the oil and 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 oil and gas properties. Prior to the HighPeak business combination, the Predecessors were each treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses relating to the operation of the oil and gas properties were reported on the income tax returns of the Predecessors’ partners. The Predecessors were subject to margin / franchise taxes in Texas, which is reflected as “Net change in income taxes” in the table above for the year ended December 31, 2019.

⁽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. The year ended December 31, 2019 in the table above reflects the change in standardized measure from that of HighPeak I, HPK LP’s Predecessor, as of December 31, 2018 to that of HPK LP as of December 31, 2019 and amounts are combined for the period from January 1, 2019 to September 30, 2019 of HighPeak I and from October 1, 2019 to December 31, 2019 of HPK LP. There was no third-party reserve report prepared for HighPeak I as of October 1, 2019 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 Predecessors and Successor in a meaningful context.