(15) Supplementary Oil and Natural Gas Disclosures—(Unaudited)

Our estimates of proved reserves are based on a reserve report prepared as of December 31, 2013 by the independent petroleum engineering firm Netherland, Sewell & Associates, Inc. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant professional judgment 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, but not limited to, 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. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the professional judgment required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

The following table sets forth our estimated net proved reserves, changes in our estimated net proved reserves and our net proved developed and undeveloped reserves.


	Oil (Mbbls)		Gas (Mmcf)		Oil Equivalent (Mboe)
Estimated Proved Reserves:
December 31, 2010		17,223		61,251		27,431
Acquisitions (a)		7,987		8,640		9,427
Extensions and discoveries		2,266		4,664		3,043
Revisions		2,778		(6,678)		1,666
Production		(2,953)		(9,092)		(4,468)
December 31, 2011		27,301		58,785		37,099
Acquisitions (b)		16,430		115,876		35,742
Extensions and discoveries (c)		6,388		10,241		8,095
Revisions		1,128		4,033		1,800
Production		(3,805)		(8,996)		(5,304)
December 31, 2012		47,442		179,939		77,432
Acquisitions		366		209		401
Sales		(1,415)		(916)		(1,568)
Extensions and discoveries (d)		7,354		20,247		10,729
Revisions		3,952		(10,128)		2,264
Production		(6,182)		(15,767)		(8,810)
December 31, 2013		51,517		173,584		80,448
Proved developed reserves:
December 31, 2011		24,791		52,739		33,581
December 31, 2012		37,908		120,687		58,022
December 31, 2013		39,439		107,687		57,387
Proved undeveloped reserves:
December 31, 2011		2,510		6,046		3,518
December 31, 2012		9,534		59,252		19,409
December 31, 2013		12,078		65,897		23,061

(a)Reserves acquired in the acquisitions of the ASOP Properties and Main Pass Interests.

(b)Reserves acquired in the acquisitions of the Hilcorp Properties and the ST41 Interests.

(c)Includes extensions and discoveries across 6 different fields, primarily within our West Delta and Ship Shoal areas. These extensions and discoveries added volumes ranging from 18 Mboe to 1.2 Mmboe each, with three exceeding 1.0 Mmboe each.

(d)Includes extensions and discoveries across 12 different fields, primarily within our Ship Shoal and West Delta areas. The Ship Shoal 208 field accounts for 46% of our total extensions and discoveries with 4,973 Mboe, consisting of 3,967 Mbbls of oil and 6,035 Mmcf of produced gas. The remaining 11 locations account for up to 16% each of total extensions and discoveries with reserves ranging from 10 Mboe to 1.6 Mmboe.

Capitalized costs for oil and natural gas producing activities consist of the following:


	Year Ended December 31,
	2013		2012
	(In thousands)
Proved properties	$	2,307,891	$	1,982,657
Unproved properties		39,191		36,992
Accumulated depreciation, depletion and amortization		(614,068)		(424,520)
Net capitalized costs	$	1,733,014	$	1,595,129

The following table sets forth the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves.


	Year Ended December 31,
	2013		2012		2011
	(In thousands)
Acquisitions — Proved (1)	$	46,047	$	706,322	$	261,812
Acquisitions — Unproved		2,200		7,496		14
Exploration		46,100		43,338		17,129
Development (2)		303,245		180,938		83,577
Costs incurred	$	397,592	$	938,094	$	362,532

(1)For the year ended December 31, 2013, includes $29.7 million associated with the Hilcorp Acquisition and $16.7 million associated with the WD29 Acquisition. See Note 2, “Acquisitions and Dispositions” for more information.

(2)Includes our estimates during the years ended December 31, 2013, 2012 and 2011 of incurred asset retirement obligations associated with finding and developing our proved oil and natural gas reserves of $1.2 million, $1.2 million and $0.2 million, respectively.

Expenditures incurred for exploratory dry holes are included in investing activities in the consolidated statements of cash flows.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

The following information has been developed utilizing procedures prescribed by ASC 932. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of our oil and natural gas reserves or the current value of the Company.

We believe that the following factors should be taken into account in reviewing the following information: (1) future costs and sales prices are likely to differ materially from those required to be used in these calculations; (2) due to future market conditions, governmental regulations and other factors, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) the use of a 10% discount rate, while mandated under ASC 932, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

The Standardized Measure of Discounted Future Net Cash Flows uses future cash inflows estimated using oil and natural gas prices computed by applying the use of physical pricing based on the simple average of the closing price on the first day of each of the twelve months during the fiscal year (as required by ASC 932) and by applying historical adjustments, including transportation, quality differentials, and purchaser bonuses, on an individual property basis, to the year-end quantities of estimated proved reserves. The historical adjustments applied to the computed prices are determined by comparing our historical realized price experience with the comparable historical market, or posted, price. These adjustments can vary significantly over time both in amount and as a percentage of the posted price, especially related to our oil prices during periods when the market price for oil varies widely. The price adjustments reflected in our computed reserve prices may not represent the amount of price adjustments we may actually obtain in the future when we sell our production, nor do they give effect to any hedging transactions that we may enter into. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs with the assumption of the continuation of existing economic conditions in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% annual discount rate in computing Standardized Measure of Discounted Future Net Cash Flows is required by ASC 932.

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


	Year Ended December 31,
	2013		2012
	(In thousands)
Future cash inflows	$	5,937,536	$	5,401,290
Future production costs		(1,957,868)		(1,823,303)
Future development costs (1)		(1,085,440)		(936,580)
Future income taxes		(641,536)		(537,546)
Future net cash flows after income taxes		2,252,692		2,103,861
10% annual discount for estimated timing of cash flows		(603,614)		(529,579)
Standardized measure of discounted future net cash flows	$	1,649,078	$	1,574,282

(1)

Future development costs as of December 31, 2013, include $569.9 million of estimated abandonment and decommissioning costs, net of $25.8 million of estimated salvage values. Future development costs as of December 31, 2012 include $466.9 million of estimated abandonment and decommissioning costs, net of $32.6 million of estimated salvage values.

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2013 and 2012 is as follows:


	Year Ended December 31,
	2013		2012
	(In thousands)
Beginning of the period	$	1,574,282	$	876,169
Sales and transfers of oil and natural gas produced, net of production costs		(513,906)		(317,059)
Net changes in prices and production costs		96,751		(244,824)
Purchase of minerals in place		26,708		797,085
Sales of minerals in place		(64,539)		-
Extensions, discoveries and improved recoveries, net of future production costs		363,493		452,258
Revision of quantity estimates		84,490		55,133
Previously estimated development costs incurred during the period		33,920		39,321
Changes in estimated future development costs		18,229		746
Changes in production rates (timing) and other		(113,022)		(14,157)
Accretion of discount		197,927		110,070
Net change in income taxes		(55,255)		(180,460)
Net increase (decrease)		74,796		698,113
End of period	$	1,649,078	$	1,574,282

At December 31, 2013 and 2012, the computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves was based on the following computed prices:


	2013		2012
per barrel of oil	$	105.30	$	105.13
per Mcf for natural gas	$	3.73	$	2.92