Note 19 – Supplemental Information on Oil and Natural Gas Operations (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States. Discontinued operations information comprising of the RNR interests which were not acquired in the Transactions have not been included in the Supplemental Information for Crude Oil Producing Activities for each period presented below.

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:

The following table sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations.

Proved oil and gas reserve estimates as of December 31, 2020, 2019 and 2018 were prepared by Ryder Scott Company, L.P. independent petroleum engineers. 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 prices.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

	Oil			Natural Gas			Natural Gas Liquids			Total
	(MBbls)			(MMcf)			(MBbls)			(MBOE)

Proved Developed and Undeveloped Reserves:
As of December 31, 2017		18,076			58,790			4,318			32,192
Purchase of reserves in place		23			83			13			50
Extensions and discoveries		-			-			-			-
Revisions of previous estimates		421			7,514			86			1,759
Divestiture of reserves		(2,150	)		(6,155	)		(969	)		(4,145	)
Production		(1,158	)		(4,047	)		(285	)		(2,117	)
As of December 31, 2018		15,212			56,185			3,163			27,740
Purchase of reserves in place		32			70			12			56
Extensions and discoveries		215			553			71			378
Revisions of previous estimates		(1,984	)		(6,950	)		(230	)		(3,373	)
Production		(879	)		(3,588	)		(297	)		(1,774	)
As of December 31, 2019		12,596			46,270			2,719			23,027
Purchase of reserves in place		62			62			-			72
Extensions and discoveries		34			797			12			179
Revisions of previous estimates		(2,114	)		4,935			(298	)		(1,590	)
Production		(836	)		(3,528	)		(247	)		(1,671	)
As of December 31, 2020		9,742			48,536			2,186			20,017

Proved Developed Reserves
December 31, 2018		3,857			18,700			1,293			8,267
December 31, 2019		3,900			18,016			1,230			8,133
December 31, 2020		3,291			19,755			1,164			7,747

Proved Undeveloped Reserves:
December 31, 2018		11,355			37,485			1,870			19,473
December 31, 2019		8,696			28,254			1,489			14,894
December 31, 2020		6,451			28,781			1,022			12,270

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs.

During the year ended December 31, 2020, the Company’s negative revisions of previous estimates of 1,590 MBOE resulted primarily from reducing the existing PUD locations by 269 wells due to a change in development timing and lower commodity prices. The purchase of reserves in place of 72 MBOE were due to multiple acquisitions located within the Eagle Ford Shale.

During the year ended December 31, 2019, the Company’s negative revisions of previous estimates of 3,373 MBOE resulted primarily from reducing the existing PUD locations by 314 wells due to a change in development timing and lower commodity prices. The purchase of reserves in place of 56 MBOE were due to multiple acquisitions located within the Eagle Ford Shale.

During the year ended December 31, 2018, the Company’s positive revisions of previous estimates of 1,759 MBOE resulted primarily from the drilling of 92 new wells and from 225 new proved undeveloped locations added. The purchase of reserves in place of 50 MBOE were due to multiple acquisitions primarily located in Karnes county within the Eagle Ford Shale.

The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2020, 2019 and 2018:

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows:

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

	December 31,
	2020			2019			2018
	(in thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	458,350		$	608,870		$	595,579
Purchase of minerals in place		2,134			1,256			1,092
Sales of oil and natural gas, net of production costs		(35,281	)		(59,949	)		(91,180	)
Extensions and discoveries		1,462			9,711			-
Net changes in prices and production costs		(148,892	)		(91,386	)		165,659
Revisions of previous quantity estimates		(72,896	)		(92,479	)		41,728
Divestiture of reserves		-			-			(73,755	)
Net changes in income taxes		25,419			20,613			(49,758	)
Accretion of discount		44,279			65,863			59,558
Net changes in timing of production and other		(22,763	)		(4,149	)		(40,053	)
Standardized measure of discounted future net cash flows at the end of the period	$	251,812		$	458,350		$	608,870