Disclosures about oil and natural gas activities (unaudited)

The estimate of proved reserves and related valuations at the end of each period presented were based upon the reports of Cawley, Gillespie & Associates, Inc., an independent petroleum and geological engineering firm, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2019 are as follows:



	Oil (MBbls)		Natural gas (MMcf)		Natural gas liquids (MBbls)		Total (MBoe)
Proved developed and undeveloped reserves
As of January 1, 2017	96,621		135,449		12,105		131,301
Sales of minerals in place	(74,918	)	(1,663	)	(46	)	(75,241	)
Extensions and discoveries	8,957		39,843		5,442		21,040
Revisions (1)	3,515		11,135		2,216		7,586
Production	(4,571	)	(14,598	)	(1,395	)	(8,399	)
Balance at December 31, 2017	29,604		170,166		18,322		76,287
Sales of minerals in place	(2,422	)	(14,184	)	(1,374	)	(6,160	)
Extensions and discoveries	6,545		69,189		9,329		27,406
Revisions (1)	1,254		12,596		1,411		4,764
Production	(2,684	)	(17,549	)	(1,881	)	(7,490	)
Balance at December 31, 2018	32,297		220,218		25,807		94,807
Sales of minerals in place	—		—		—		—
Extensions and discoveries	4,766		48,967		8,343		21,271
Revisions (1)	(6,703	)	(26,340	)	1,166		(9,927	)
Production	(3,111	)	(22,095	)	(2,799	)	(9,593	)
Balance at December 31, 2019	27,249		220,750		32,517		96,558
Proved developed reserves:
January 1, 2017	28,590		108,800		9,352		56,076
December 31, 2017	18,301		123,451		11,858		50,734
December 31, 2018	18,051		135,425		14,846		55,468
December 31, 2019	18,447		152,187		20,949		64,761
Proved undeveloped reserves:
January 1, 2017	68,031		26,649		2,753		75,225
December 31, 2017	11,303		46,715		6,464		25,553
December 31, 2018	14,246		84,793		10,961		39,339
December 31, 2019	8,802		68,563		11,568		31,797


(1)	The revisions in 2019 and 2018 were primarily due to changes in pricing during the respective periods. The upward revision in 2017 was primarily due to changes in pricing and costs.

The following information was developed using procedures prescribed by U.S. GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

We believe that, in reviewing the information that follows, the following factors should be taken into account:


•	future costs and sales prices will probably differ from those required to be used in these calculations;


•	actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;


•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and


•	future net revenues may be subject to different rates of income taxation.

Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 9: Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

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



	December 31,
	2019			2018			2017
Future cash flows	$	2,424,620		$	3,255,771		$	2,331,940
Future production costs	(1,040,314		)	(1,187,071		)	(899,380		)
Future development and abandonment costs	(304,229		)	(450,220		)	(336,828		)
Future income tax provisions	—			—			—
Net future cash flows	1,080,077			1,618,480			1,095,732
Less effect of 10% discount factor	(565,874		)	(932,114		)	(597,859		)
Standardized measure of discounted future net cash flows	$	514,203		$	686,366		$	497,873

The 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,
	2019			2018			2017
Beginning of year	$	686,366		$	497,873		$	528,781
Sale of oil and natural gas produced, net of production costs	(170,255		)	(175,199		)	(175,246		)
Net changes in prices and production costs	(332,546		)	95,430			125,795
Extensions and discoveries	114,199			192,105			136,887
Improved recoveries	—			—			—
Changes in future development costs	116,677			(2,424		)	(4,879		)
Development costs incurred during the period that reduced future development costs	38,270			6,277			37,912
Revisions of previous quantity estimates (1)	(8,152		)	79,192			68,428
Purchases and sales of reserves in place, net	—			(45,222		)	(238,445		)
Accretion of discount	58,668			36,386			24,267
Net change in income taxes	—			—			—
Changes in production rates and other	10,976			1,948			(5,627		)
End of year	$	514,203		$	686,366		$	497,873


(1)	Amounts in 2019 and 2018 are primarily the result of changes in pricing. Amounts in 2017 are primarily the result of increased volumes due to changes in pricing and costs.

The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.



	2019		2018		2017
Oil (per Bbl)	$	55.69	$	65.56	$	51.34
Natural gas (per Mcf)	$	2.58	$	3.10	$	2.98
Natural gas liquids (per Bbl)	$	16.21	$	25.56	$	24.17