Note 14—Supplemental Oil and Gas Information (unaudited)

Costs Incurred For Oil and Natural Gas Producing Activities

The following table sets forth the capitalized costs incurred in the Predecessor’s oil and natural gas production, exploration, and development activities:


	For the Years Ended December 31,
	2015		2014		2013
	(in thousands)
Acquisition costs:
Proved properties	$	14,268	$	5,758	$	10,208
Unproved properties		28,955		16,409		17,204
Development costs		87,452		324,802		151,562
Total	$	130,675	$	346,969	$	178,974

Oil and Gas Reserve Quantities

The reserve estimates presented below were made in accordance with U.S. GAAP requirements for disclosures about oil and natural gas producing activities and Securities and Exchange Commission (“SEC”) rules for oil and natural gas reporting reserves estimation and disclosure.

Estimates of the Predecessor’s proved oil and natural gas reserves at December 31, 2015 and 2014 were prepared by Netherland, Sewell & Associates, Inc. Estimates of the Predecessor’s proved oil and natural gas reserves at December 31, 2013 were prepared internally by management and not by independent third‑party petroleum engineers.

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 following table summarizes the trailing 12‑month index prices used in the reserve estimates for the years ended December 31, 2015, 2014 and 2013. The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows (“standardized measure”):


	For the Years Ended
	December 31,
	2015		2014		2013
	(in thousands)
Oil (per Bbl)	$	41.85	$	84.94	$	92.05
Gas (per Mcf)	$	1.71	$	4.70	$	3.76
NGLs (per Bbl)	$	13.94	$	22.70	$	26.05

The table below presents a summary of changes in the Predecessor’s estimated proved reserves:


	For the Years Ended December 31,
	2015			2014			2013
			Natural			Natural			Natural
	Crude	Natural	Gas	Crude	Natural	Gas	Crude	Natural	Gas
	Oil	Gas	Liquids	Oil	Gas	Liquids	Oil	Gas	Liquids
	(MBbls)	(MMcf)	(MBbls)	(MBbls)	(MMcf)	(MBbls)	(MBbls)	(MMcf)	(MBbls)
Total Proved Reserves:
Beginning of the year	19,850	27,414	1,551	18,510	6,968	525	11,422	10,032	967
Extensions and discoveries	9,444	11,927	1,432	16,122	22,575	1,127	12,459	5,189	300
Revisions of previous estimates	(5,109)	(5,204)	995	56	178	180	426	837	80
Purchases of reserves in place	844	1,363	204	162	192	23	109	94	8
Divestitures of reserves in place	—	—	—	(13,572)	(387)	(69)	(5,193)	(8,387)	(732)
Production	(1,830)	(3,058)	(331)	(1,428)	(2,112)	(235)	(713)	(797)	(98)
End of the year	23,199	32,442	3,851	19,850	27,414	1,551	18,510	6,968	525
Proved Developed Reserves:
Beginning of the year	8,026	11,959	766	6,021	4,837	382	2,978	2,078	285
End of the year	9,347	12,711	1,603	8,026	11,959	766	6,021	4,837	382
Proved Undeveloped Reserves:
Beginning of the year	11,823	15,455	785	12,489	2,131	143	8,444	7,954	682
End of the year	13,852	19,731	2,248	11,823	15,455	785	12,489	2,131	143

Proved reserves at December 31, 2015 increased 25% to 32,457 MBoe, compared to 25,970 MBoe at December 31, 2014.

During 2015, the Predecessor added 12,864 MBoe of proved reserves through extensions, primarily due to its drilling activity.

During 2015, the Predecessor had net negative revisions of 4,981 MBoe. The significant decrease in commodity prices seen in 2015 resulted in negative revisions related to the conversion of approximately 6,794 MBoe from PUDs to unproved reserves, partially offset by a positive revision in performance.

During 2015, the Predecessor acquired 1,275 MBoe of proved reserves. Refer to Note 4—Acquisitions and Divestitures.

During 2014, the Predecessor added 21,012 MBoe of proved reserves through extensions and discoveries, primarily due to its continued development drilling program and 265 MBoe of proved reserves, due to better than expected performance of its proved developed reserves.

During 2014, the Predecessor divested of 13,706 MBoe of proved reserves. Refer to Note 4—Acquisitions and Divestitures.

During 2013, the Predecessor added 6,934 MBoe of proved reserves through extension and discoveries, primarily from the drilling of new wells and from new proved undeveloped locations added during the year. Additionally, the Predecessor added 6,799 MBoe through improved recovery. Improved recovery reflects reserve additions that result from the application of tertiary recovery methods such as CO₂ injection at the Predecessor’s Caprock field. The Caprock field was sold in May 2014.

During 2013, the Predecessor had revisions of 646 MBoe due to better than expected performance attributable to its proved developed reserves.

During 2013, the Predecessor divested of 7,323 MBoe for certain properties sold. Refer to Note 4—Acquisitions and Divestitures.

Standardized Measure of Discounted Future Net Cash Flows

The Predecessor computes a standardized measure of discounted future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year‑end estimated future reserve quantities. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year‑end costs and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Predecessor’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.

The following table presents the Predecessor’s standardized measure of discounted future net cash flows for the periods indicated:


	December 31,
	2015		2014		2013
	(in thousands)
Future cash inflows	$	1,079,962	$	1,850,205	$	1,743,612
Future development costs		(277,837)		(440,366)		(223,227)
Future production costs		(450,058)		(457,236)		(601,614)
Future income tax expenses		(6,643)		(10,834)		(3,540)
Future net cash flows		345,424		941,769		915,231
10% discount to reflect timing of cash flows		(210,355)		(575,886)		(543,924)
Standardized measure of discounted future net cash flows	$	135,069	$	365,883	$	371,307

A summary of changes in the standardized measure of discounted future net cash flows is as follows for the periods indicated:


	For the Years Ended December 31,
	2015		2014		2013
	(in thousands)
Standardized measure of discounted future net cash flows, beginning of the period	$	365,883	$	371,307	$	257,083
Sales of oil, natural gas and NGLs, net of production costs		(58,534)		(102,488)		(47,424)
Purchase of minerals in place		14,416		5,650		4,410
Divestiture of minerals in place		—		(242,344)		(73,174)
Extensions and discoveries, net of future development costs		57,894		312,532		99,107
Change in estimated development costs		16,100		10,386		7,520
Net change in prices and production costs		(494,734)		(3,027)		21,601
Change in estimated future development costs		247,642		2,935		(40,783)
Revisions of previous quantity estimates		(51,342)		924		135,759
Accretion of discount		37,517		13,561		19,000
Net change in income taxes		1,601		(2,762)		(35)
Net change in timing of production and other		(1,374)		(791)		(11,757)
Standardized measure of discounted future net cash flows, end of the period	$	135,069	$	365,883	$	371,307