Note 13—Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to our oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands):


	December 31,
	2017			2016
Proved properties	$	2,440,811		$	2,235,835
Unproved oil and gas properties, not subject to amortization		72,002			72,360

Total oil and gas properties		2,512,813			2,308,195
Less: Accumulated depletion and amortization		(1,423,829	)		(1,268,276	)

Net capitalized costs	$	1,088,984		$	1,039,919

Depletion and amortization rate per Boe	$	14.85		$	13.82

Included in the depletable basis of our proved oil and gas properties is the estimate of our proportionate share of asset retirement costs relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2017 and 2016 our oil and gas asset retirement obligations totaled $214.7 million and $220.0 million, respectively.

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.


	Year Ended December 31,
	2017		2016		2015
Property acquisition costs:
Proved properties	$	1,108	$	77,906	$	68,463
Unproved properties, not subject to amortization		5,778		15,919		39,265

Total property acquisition costs		6,886		93,825		107,728
Exploration costs		82,887		27,807		25,908
Development costs		114,846		195,869		228,257

Total costs incurred	$	204,619	$	317,501	$	361,893

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

We have employed full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. Our Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all of our oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located offshore in the Gulf of Mexico and lower Gulf Coast regulated by the United States, the State of Louisiana, or the State of Texas.

At December 31, 2017 and 2016, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and complied for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. At December 31, 2015, 100% of proved oil, natural gas and NGL reserves attributable to our net interests in legacy oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Ryder Scott, independent petroleum engineers and geologists and 100% of proved oil, natural gas and NGL reserves attributable to the assets acquired in the GCER Acquisition were estimated and compiled for reporting purposes by our reservoir engineers and audited by NSAI.

The following table presents our estimated proved reserves at our net ownership interest:


	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Total proved reserves at December 31, 2014		46,120			136,232			4,096			72,921

Revision of previous estimates		(3,435	)		(22,580	)		207			(6,991	)
Production		(5,161	)		(21,458	)		(588	)		(9,325	)
Purchases of reserves		4,029			30,527			385			9,502
Extensions and discoveries		4,801			6,503			481			6,366

Total proved reserves at December 31, 2015		46,354			129,224			4,581			72,473
Revision of previous estimates		(1,712	)		10,024			(352	)		(394	)
Production		(5,126	)		(19,001	)		(603	)		(8,896	)
Purchases of reserves		11,128			11,208			950			13,946
Extensions and discoveries		21,722			19,149			1,660			26,573

Total proved reserves at December 31, 2016		72,366			150,604			6,236			103,702
Revision of previous estimates		(2,673	)		(15,860	)		250			(5,067	)
Production		(7,048	)		(16,308	)		(706	)		(10,472	)
Extensions and discoveries		10,159			9,220			767			12,462

Total proved reserves at December 31, 2017		72,804			127,656			6,547			100,625

Total proved developed reserves as of:
December 31, 2015		33,016			90,432			3,383			51,471
December 31, 2016		45,753			96,122			4,032			65,805
December 31, 2017		37,460			77,577			3,315			53,704
Total proved undeveloped reserves as of:
December 31, 2015		13,338			38,792			1,198			21,002
December 31, 2016		26,613			54,482			2,204			37,897
December 31, 2017		35,344			50,079			3,232			46,921

(1)	One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from drilling our Tornado II exploration prospect. These were offset by a decrease of 10.5 MMBoe of production and 5.1 MMBoe of negative performance revisions.

During 2016, the Company added 13.9 MMBoe of estimated proved reserves through the purchase of reserves from the asset transaction of the Sojitz Acquisition. The Company also added 26.6 MMBoe of estimated proved reserves from extensions and discoveries from successful drilling of the Tornado exploration well in the Phoenix Field.

During 2015, the Company added 9.5 MMBoe of estimated proved reserves through purchases of reserves consisting of 5.1 MMBoe and 4.4 MMBoe in estimated proved reserves acquired in the GCER Acquisition and DGE Acquisition, respectively. Downward revisions of previous estimates of 7.0 MMBoe were primarily due to the significant decline in commodity prices resulting in uneconomic reserves.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to our interest in proved oil, natural gas and NGL reserves (in thousands):


	December 31,
	2017			2016			2015
Future cash inflows	$	4,308,863		$	3,390,612		$	2,786,828
Future costs:
Production		(815,509	)		(775,354	)		(1,363,585	)
Development and abandonment		(823,164	)		(664,254	)		(646,161	)

Future net cash flows before income taxes		2,670,190			1,951,004			777,082
Future income tax expense		—			—			—

Future net cash flows before income taxes		2,670,190			1,951,004			777,082
Discount at 10% annual rate		(862,521	)		(614,969	)		(174,101	)

Standardized measure of discounted future net cash flows	$	1,807,669		$	1,336,035		$	602,981

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of our derivative instruments. See the following table for base prices used in determining the standardized measure:


	Year Ended December 31,
	2017		2016		2015
Oil price per Bbl	$	51.36	$	40.02	$	50.72
Natural gas prices per Mcf	$	3.20	$	2.66	$	2.75
NGL price per Bbl	$	24.64	$	14.96	$	17.60

Future net cash flows are discounted at the prescribed rate of 10%. We caution that actual future net cash flows may vary considerably from these estimates. Although our estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to our proved oil, natural gas and NGL reserves are as follows (in thousands):


	Year Ended December 31,
	2017			2016			2015
Standardized measure, beginning of year	$	1,336,035		$	602,981		$	1,888,958
Changes during the year:
Sales, net of production costs		(288,942	)		(114,625	)		(117,344	)
Net change in prices and production costs		555,100			80,174			(1,879,436	)
Changes in future development costs		(156,282	)		2,292			92,182
Development costs incurred		146,687			108,484			273,532
Accretion of discount		133,603			60,298			188,896
Net change in income taxes		—			—			—
Purchases of reserves		—			222,581			229,052
Extensions and discoveries		328,565			479,833			91,722
Sales of reserves		—			—			—
Net change due to revision in quantity estimates		(113,629	)		(5,685	)		(103,842	)
Changes in production rates (timing) and other		(133,468	)		(100,298	)		(60,739	)

Total		471,634			733,054			(1,285,977	)

Standardized measure, end of year	$	1,807,669		$	1,336,035		$	602,981