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.

Capitalized oil and natural gas costs

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



	December 31,
	2017			2016
	(In thousands)
Oil and Natural Gas Properties:
Proved properties	$	5,126,829		$	3,429,742
Unproved properties	4,105,865			1,730,519
Total oil and natural gas properties	9,232,694			5,160,261
Accumulated depreciation, depletion, amortization	(1,009,893		)	(687,685		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Net oil and natural gas properties capitalized	$	7,079,303		$	3,329,078

Costs incurred in oil and natural gas activities

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



	Year Ended December 31,
	2017		2016		2015
	(In thousands)
Acquisition costs
Proved properties	$	452,661	$	72,044	$	64,340
Unproved properties	2,692,000		752,117		448,638
Development costs	145,362		47,575		42,749
Exploration costs	779,728		329,122		319,102
Capitalized asset retirement costs	2,682		4,030		3,458
Total	$	4,072,433	$	1,204,888	$	878,287

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule 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 consolidated net operating results of our oil, natural gas and natural gas liquids operations.



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Oil, natural gas and natural gas liquid sales	$	1,186,275		$	527,107		$	446,733
Lease operating expenses	(126,524		)	(82,428		)	(82,625		)
Production and ad valorem taxes	(73,505		)	(34,456		)	(32,990		)
Gathering and transportation	(12,834		)	(11,606		)	(6,091		)
Depreciation, depletion, and amortization	(321,870		)	(176,369		)	(216,056		)
Impairment	—			(245,536		)	(814,798		)
Asset retirement obligation accretion expense	(1,391		)	(1,064		)	(833		)
Income tax benefit (expense)	19,568			(192		)	201,310
Results of operations	$	669,719		$	(24,544	)	$	(505,350	)

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2017, 2016 and 2015 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.

The changes in estimated proved reserves are as follows:



	Oil (MBbls)		Natural Gas Liquids (MBbls)		Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2015	75,690		18,542		111,605
Extensions and discoveries	48,725		12,056		53,453
Revisions of previous estimates	(12,130	)	(4,081	)	(14,726	)
Purchase of reserves in place	2,775		1,165		7,102
Production	(9,081	)	(1,678	)	(7,931	)
As of December 31, 2015	105,979		26,004		149,503
Extensions and discoveries	55,069		13,962		64,758
Revisions of previous estimates	(12,483	)	(1,888	)	(34,519	)
Purchase of reserves in place	2,537		1,455		7,567
Divestitures	(366	)	—		(1,985	)
Production	(11,562	)	(2,399	)	(10,428	)
As of December 31, 2016	139,174		37,134		174,896
Extensions and discoveries	99,980		20,825		109,032
Revisions of previous estimates	(7,715	)	(1,466	)	(10,065	)
Purchase of reserves in place	24,322		2,633		34,640
Divestitures	(1,163	)	(461	)	(2,474	)
Production	(21,417	)	(4,056	)	(20,660	)
As of December 31, 2017	233,181		54,609		285,369

Proved Developed Reserves:
January 1, 2015	43,886		11,221		68,264
December 31, 2015	60,569		15,418		96,871
December 31, 2016	79,457		22,080		105,399
December 31, 2017	141,246		35,412		190,740

Proved Undeveloped Reserves:
January 1, 2015	31,804		7,321		43,341
December 31, 2015	45,409		10,586		52,632
December 31, 2016	59,717		15,054		69,497
December 31, 2017	91,935		19,198		94,629

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, 2017, the Company’s extensions and discoveries of 138,977 MBOE resulted primarily from the drilling of 102 new wells and from 87 new proved undeveloped locations added. Partnership royalty interests accounted for 8% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of 2,550 MBOE from reclassifying PUD locations due to anticipated timing, with the remaining 8,308 MBOE being technical revisions. Delaware Basin working interest purchases accounted for 87% of the total purchases and Partnership royalty interest purchases accounted for 10%, with working interest purchases contributing the remainder.

During the year ended December 31, 2016, the Company’s extensions and discoveries of 69,042 MBOE resulted primarily from the drilling of 59 new wells and from 51 new proved undeveloped locations added. The Company owns the mineral interests associated with 30 of the 59 new wells and 30 of the 51 proved undeveloped locations through the Partnership. The Company’s negative revisions of previous estimates were primarily the result of 5,978 MBOE of pricing revisions and 7,253 MBOE from reclassifying 17 locations from proved undeveloped due to pricing. Purchases of reserves in place of 3,993 MBOE were primarily the result of the purchase of producing wells included with the Reeves and Ward county acreage purchase and reserves associated with multiple purchases made by the Partnership.

During the year ended December 31, 2015, the Company made one large acquisition of oil and natural gas interests in 2015 located in western Howard and eastern Martin counties. Several small acquisitions were also made in various counties including Andrews, Midland, Martin, and Glasscock counties. The reserves from these acquisitions were primarily proved producing reserves from 136 vertical wells and four horizontal wells and three vertical wells where additional interest was acquired. All of the properties were acquired for horizontal exploitation. Although there were four producing horizontal wells on the properties no PUD’s were included in the acquired properties because of very limited production from the wells at the time of acquisition. Significant extensions occurred in 2015 as a result of continued horizontal development of the Lower Spraberry and Wolfcamp B horizons. There was also initial development of the Wolfcamp A and Middle Spraberry horizons in some locations. The extensions resulted from two vertical wells and 119 horizontal wells in which the Company has a working interest and from 16 horizontal wells in which the Company has a mineral interest through its ownership in Viper. Of the two vertical wells and 135 horizontal wells, one of the vertical wells and 89 of the horizontal wells are in the proved undeveloped category. The revisions are primarily the result of lower product pricing. As a result of lower pricing, 80 vertical wells and 22 horizontal wells in which the Company has a working interest and 22 vertical wells in which the Company has a mineral interest were downgraded from the proved undeveloped category to probable or possible reserves. Additional downward revisions resulted from shorter producing lives on existing wells as a result of the wells reaching their economic limit sooner due to lower revenues.

At December 31, 2017, the Company’s estimated PUD reserves were approximately 126,904 MBOE, a 40,550 MBOE increase over the reserve estimate at December 31, 2016 of 86,354 MBOE. The following table includes the changes in PUD reserves for 2017:



	(MBOE)
Beginning proved undeveloped reserves at December 31, 2016	86,354
Undeveloped reserves transferred to developed	(31,666	)
Revisions	(4,710	)
Net purchases	6,246
Extensions and discoveries	70,680
Ending proved undeveloped reserves at December 31, 2017	126,904

The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676 MBOE from 87 gross (75 net) wells in which the Company has a working interest and 3,004 MBOE from 40 gross wells in which the Partnership owns royalty interests. Of the 87 gross wells, 26 were in the Delaware Basin. Transfers of 31,666 MBOE were the result of drilling or participating in 44 gross (37 net) horizontal wells in which the Company has a working interest and 27 gross wells in which the Company has a royalty interest or mineral interest through the Partnership. The Company owns a working interest in 23 of the 27 gross Partnership wells. Net purchases of 6,246 MBOE were primarily from the Company’s purchase in Pecos and Reeves counties. Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions.

As of December 31, 2017, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2017, approximately $145.4 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is 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, 2017, 2016 and 2015.



	December 31,
	2017			2016			2015
	(In thousands)
Future cash inflows	$	12,921,897		$	6,275,705		$	5,377,783
Future development costs	(1,123,979		)	(617,636		)	(548,239		)
Future production costs	(2,994,877		)	(1,392,852		)	(1,279,101		)
Future production taxes	(928,891		)	(459,244		)	(363,129		)
Future income tax expenses	(83,961		)	(75,595		)	(28,233		)
Future net cash flows	7,790,189			3,730,378			3,159,081
10% discount to reflect timing of cash flows	(4,033,130		)	(2,018,965		)	(1,740,948		)
Standardized measure of discounted future net cash flows	$	3,757,059		$	1,711,413		$	1,418,133

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.



	December 31,
	2017		2016		2015
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	48.03	$	39.94	$	45.07
Natural gas (per Mcf)	$	2.06	$	1.36	$	1.83
Natural gas liquids (per Bbl)	$	20.79	$	12.91	$	12.56

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



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	1,711,413		$	1,418,133		$	2,045,224
Sales of oil and natural gas, net of production costs	(986,246		)	(411,558		)	(331,119		)
Acquisition of reserves	439,396			43,142			58,849
Divestiture of reserves	(11,072		)	(5,481		)	(1,490		)
Extensions and discoveries, net of future development costs	1,791,686			779,359			629,149
Previously estimated development costs incurred during the period	190,121			85,696			129,901
Net changes in prices and production costs	577,781			(150,509		)	(1,383,698		)
Changes in estimated future development costs	(52,908		)	20,647			38,638
Revisions of previous quantity estimates	(98,857		)	(123,795		)	(377,160		)
Accretion of discount	174,185			143,134			236,716
Net change in income taxes	(9,074		)	(30,530		)	268,963
Net changes in timing of production and other	30,634			(56,825		)	104,160
Standardized measure of discounted future net cash flows at the end of the period	$	3,757,059		$	1,711,413		$	1,418,133