SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized Costs

	December 31,
	2015			2014
Oil and natural gas properties:	(in thousands)
Proved properties	$	1,627,367		$	1,248,376
Unproved properties		618,794			624,240
Total oil and natural gas properties		2,246,161			1,872,616
Less accumulated depreciation, depletion and amortization		(290,186	)		(128,044	)
Net oil and natural gas properties capitalized	$	1,955,975		$	1,744,572

Costs Incurred for Oil and Natural Gas Producing Activities

	Year Ended December 31,
	2015		2014		2013
Acquisition costs:	(in thousands)
Proved properties	$	16,422	$	233,899	$	142,695
Unproved properties		57,385		528,301		65,686
Development costs		404,291		488,673		268,400
Total	$	478,098	$	1,250,873	$	476,781

Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2015, which have been prepared and presented under SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2015 was based on an unweighted average 12-month average WTI posted price per Bbl for oil and NGLs, and a Henry Hub spot natural gas price per Mcf for natural gas, as set forth in the following table:

	Year Ended December 31,
	2015		2014		2013
Oil (per Bbl)	$	46.54	$	85.99	$	92.53
Natural gas liquids (per Bbl)	$	16.42	$	35.27	$	36.20
Natural gas (per Mcf)	$	2.53	$	4.28	$	3.46

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are located in the United States in the Permian Basin of West Texas. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a roll forward of the total proved reserves for the years ended December 31, 2015, 2014, and 2013, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

	Year Ended December 31, 2015
	Crude Oil			Liquids			Natural Gas
	(Bbls)			(Bbls)			(Mcf)			Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		47,617			22,667			123,645			90,891
Extensions and discoveries		38,518			9,232			53,044			56,590
Revisions of previous estimates		(6,688	)		(6,934	)		(11,825	)		(15,593	)
Purchases of reserves in place		1,133			551			4,138			2,374
Divestures of reserves in place		(1,896	)		(278	)		(1,488	)		(2,422	)
Production		(4,807	)		(1,500	)		(10,339	)		(8,030	)
End of the year		73,877			23,738			157,175			123,810


Proved Developed Reserves:
Beginning of the year		23,547			11,491			65,484			45,952
End of the year		27,628			10,890			77,612			51,454

Proved Undeveloped Reserves:
Beginning of the year		24,070			11,175			58,161			44,939
End of the year		46,249			12,848			79,563			72,357

	Year Ended December 31, 2014
	Crude Oil			Liquids			Natural Gas
	(Bbls)			(Bbls)			(Mcf)			Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		29,507			12,357			77,818			54,834
Extensions and discoveries		18,776			8,157			41,348			33,824
Revisions of previous estimates		(7,832	)		(528	)		(6,714	)		(9,480	)
Purchases of reserves in place		10,006			3,906			18,244			16,953
Divestures of reserves in place		—			—			—			—
Production		(2,840	)		(1,225	)		(7,051	)		(5,240	)
End of the year		47,617			22,667			123,645			90,891


Proved Developed Reserves:
Beginning of the year		13,560			4,762			31,301			23,539
End of the year		23,547			11,491			65,484			45,952

Proved Undeveloped Reserves:
Beginning of the year		15,947			7,595			46,517			31,295
End of the year		24,070			11,175			58,161			44,939

	Year Ended December 31, 2013
	Crude Oil			Liquids			Natural Gas
	(Bbls)			(Bbls)			(Mcf)			Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		12,987			4,732			30,214			22,755
Extensions and discoveries		10,378			4,840			29,489			20,132
Revisions of previous estimates		(2,029	)		(796	)		(1,813	)		(3,127	)
Purchases of reserves in place		9,223			3,695			23,937			16,908
Divestures of reserves in place		(3	)		(1	)		(7	)		(5	)
Production		(1,049	)		(113	)		(4,002	)		(1,829	)
End of the year		29,507			12,357			77,818			54,834
Proved Developed Reserves:
Beginning of the year		5,834			1,906			12,186			9,771
End of the year		13,560			4,762			31,301			23,539

Proved Undeveloped Reserves:
Beginning of the year		7,153			2,826			18,028			12,984
End of the year		15,947			7,595			46,517			31,295

Extensions and discoveries of 56,590 MBoe, 33,824 MBoe and 20,132 MBoe during the years ended December 31, 2015, 2014 and 2013, result primarily from the drilling of new wells during each year and from new proved undeveloped locations added during each year.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2015, 2014, and 2013 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

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

	December 31,
	2015			2014			2013
	(in thousands)
Future cash inflows (1)	$	4,225,912		$	5,423,551		$	3,446,766
Future development costs		(829,560	)		(642,746	)		(515,247	)
Future production costs		(1,534,011	)		(1,640,422	)		(1,097,734	)
Future income tax expenses		(240,203	)		(903,354	)		(24,127	)
Future net cash flows		1,622,138			2,237,029			1,809,658
10% discount to reflect timing of cash flows		(1,024,290	)		(1,281,400	)		(1,088,878	)
Standardized measure of discounted future net cash flows	$	597,848		$	955,629		$	720,780

(1)

Future net cash flows do not include the effects of U.S. federal income taxes on future results because the Company was a limited liability company not subject to entity-level federal income taxation as of December 31, 2013. Accordingly, no provision for federal corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, the Company’s operations located in Texas are subject to an entity-level tax, the Texas Margin Tax, at a statutory rate of up to 1.0% of income that is apportioned to Texas. Following the Corporate Reorganization, the Company was a subchapter C corporation subject to U.S. federal and state income taxes. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2013 would have been $562.5 million. The unaudited standardized measure at December 31, 2013 would have been $497.7 million.

In the foregoing determination of future cash inflows, sales prices used for oil, NGLs, and natural gas for December 31, 2015, 2014, and 2013, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of its’ predecessor’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves are as follows:

	Year Ended December 31,
	2015			2014			2013
	(in thousands)
Standardized measure of discounted future net cash flows at the beginning of the year	$	955,629		$	720,780		$	296,048
Sales of oil and natural gas, net of production costs		(185,344	)		(244,745	)		(97,365	)
Purchase of minerals in place		4,872			279,725			227,937
Divestiture of minerals in place		(53,018	)		—			(122	)
Extensions and discoveries, net of future development costs		485,380			537,241			204,135
Previously estimated development costs incurred during the period		12,560			96,881			57,158
Net changes in prices and production costs		(821,783	)		(74,080	)		11,463
Changes in estimated future development costs		77,621			(9,517	)		2,793
Revisions of previous quantity estimates		(225,485	)		(126,395	)		(41,242	)
Accretion of discount		131,442			73,107			30,010
Net change in income taxes		249,065			(348,501	)		(6,240	)
Net changes in timing of production and other		(33,091	)		51,133			36,205
Standardized measure of discounted future net cash flows at the end of the year	$	597,848		$	955,629		$	720,780