(19) Supplementary Oil and Natural Gas Disclosures (Unaudited)

On January 31, 2010, Wild Well acquired 100% ownership of Shell Offshore, Inc.’s Gulf of Mexico Bullwinkle platform and its related assets and assumed the related decommissioning obligation. Immediately after Wild Well acquired these assets, it conveyed an undivided 49% interest in these assets and the related well plugging and abandonment obligations to Dynamic Offshore, which operates these assets. The Company also had an interest in oil and gas operations through its equity-method investment in Dynamic Offshore (see note 7).

In January 2010, the Financial Accounting Standards Board issued an update to the authoritative guidance related to oil and gas reserve estimation and disclosures that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for those companies that have significant oil- and gas-producing activities. For the years ended December 31, 2010 and 2011, the Company was deemed to have significant oil and gas activities. For the year ended December 31, 2012, those activities are no longer considered significant.

The Company’s December 31, 2011 estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. The Company’s December 31, 2010 estimates of proved reserves were based on reserve reports prepared by DeGoyler and MacNaughton and Netherland, Sewell & Associates Inc. Users of this information should be aware that the process of estimating quantities of “proved”, “proved developed” and “proved undeveloped” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple 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 subjective decisions 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. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.

Oil and Natural Gas Reserves

The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:



			Company's Share of
	Consolidated		Equity-Method Investments
	Crude Oil	Natural Gas	Crude Oil	Natural Gas
	(Mbbls)	(Mmcf)	(Mbbls)	(Mmcf)

Proved-developed and undeveloped reserves:
December 31, 2009	-	-	3,242	23,255
Purchase of reserves in place	5,686	4,377	34	8
Revisions	723	1,572	564	692
Extensions, discoveries and other additions	-	-	-	413
Change in ownership percentage	-	-	(32)	(1,347)
Production	(427)	(648)	(413)	(2,910)

December 31, 2010	5,982	5,301	3,395	20,111
Purchase of reserves in place	-	-	958	8,045
Revisions	887	1,338	412	(547)
Extensions, discoveries and other additions	-	-	-	-
Sale of reserves in-place	-	-	(1,159)	(8,467)
Production	(439)	(371)	(399)	(906)

December 31, 2011	6,430	6,268	3,207	18,236

Proved-developed reserves:
December 31, 2010	4,166	3,848	2,972	18,228
December 31, 2011	3,495	3,229	2,606	14,695

Proved-undeveloped reserves:
December 31, 2010	1,817	1,453	423	1,885
December 31, 2011	2,935	3,039	602	3,542

Costs Incurred in Oil and Natural Gas Activities

The following table displays certain information regarding the costs incurred associated with finding, acquiring and developing the Company’s proved oil and natural gas reserves for the years ended December 31, 2011 and 2010 (in thousands).



			Company's Share of
	Consolidated		Equity-Method Investments
	Years Ended December 31,		Years Ended December 31,
	2011	2010	2011	2010

Acquisition of properties - proved	$ -	$ 34,336	$ 32,586	$ 629
Acquisition of properties - unproved	-	-	-	118
Exploratory costs	-	359	-	-
Development costs	10,560	30	18,367	9,980

Total costs incurred	$ 10,560	$ 34,725	$ 50,953	$ 10,727

Capitalized costs for oil and gas producing activities consist of the following (in thousands):



			Company's Share of
	Consolidated		Equity-Method Investments
	Years Ended December 31,		Years Ended December 31,
	2011	2010	2011	2010

Unproved oil and gas properties	$ -	$ -	$ 13,559	$ 24,097
Proved oil and gas properties	44,109	34,336	159,527	144,324
Accumulated depreciation, depletion and amortization	(8,215)	(3,038)	(52,764)	(49,849)

Capitalized costs, net	$ 35,894	$ 31,298	$ 120,322	$ 118,572

Results of Operations

The following table sets forth the Company’s results of operations for producing activities:



	Years Ended December 31,
	2011	2010
Consolidated Entities
Revenues
Sales	$ 54,442	$ 39,410

Production costs	12,293	9,511
Exploration expenses	-	359

Depreciation, depletion and
amortization	11,928	10,057
	30,221	19,483
Income tax expenses	10,789	7,014

Results of operations from producing
activities (excluding corporate overhead)	$ 19,432	$ 12,469

Company's share of equity-method investments
Revenues
Sales	$ 53,181	$ 56,964

Production costs	22,034	23,375
Exploration expenses	-	105

Depreciation, depletion and
amortization	18,449	18,557
	12,698	14,927
Income tax expenses	4,533	5,373

Results of operations from producing
activities (excluding corporate overhead)	$ 8,165	$ 9,554

The Company’s consolidated oil and gas operations, as well as its share of equity-method investment are in the Gulf of Mexico. The Company’s consolidated entity’s average sales price was $108.79 per barrel of oil and $3.45 per mcf of gas in 2011 and $77.04 per barrel of oil and $5.00 per mcf of gas in 2010. Average production costs were $12.51 and $19.99 per barrel of oil equivalent in years ended December 31, 2011 and 2010, respectively. The Company’s share of its equity-method investment’s average sales price was $113.28 per barrel of oil and $4.40 per mcf of gas in 2011 and $79.21 per barrel of oil and $4.78 per mcf of gas in 2010. Average production costs were $26.30 and $25.35 per barrel of oil equivalent in 2011 and 2010, respectively.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

The following information has been developed utilizing procedures prescribed by authoritative guidance related to oil and gas activities. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its 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 the Company.

The Company believes that the following factors should be taken into account in reviewing this information: (1) future costs and selling prices will likely differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate 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.

Under the standardized measure, future cash inflows were estimated by applying period-end oil and natural gas prices adjusted for differentials. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow 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% discount rate is required by authoritative guidance related to oil and gas activities.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves at December 31, 2011 and 2010 is as follows (in thousands):



			Company's Share of
	Consolidated		Equity-Method Investments
	2011	2010	2011	2010
Future cash inflows	$ 701,170	$ 486,199	$ 414,246	$ 356,126
Future production costs	(126,627)	(43,392)	(100,848)	(83,215)
Future development and abandonment costs	(58,388)	(86,125)	(67,760)	(84,260)
Future income tax expenses	(185,816)	(129,262)	(73,202)	(66,161)
Future net cash flows	330,339	227,420	172,436	122,490
10% annual discount for estimated timing of
cash flows	92,590	57,928	39,704	20,014
Standardized measure of discounted future
net cash flows	$ 237,749	$ 169,492	$ 132,732	$ 102,476

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, 2011 and 2010 is as follows (in thousands):



	Consolidated		Company's Share of Equity-Method Investment
	2011	2010	2011	2010
Beginning of the period	$ 169,492	$ -	$ 102,476	$ 64,136
Net change in sales and transfer prices and in
production (lifting) costs related to future production	62,881	102,726	27,944	57,626
Changes in estimated future development costs	8,297	2,950	(8,862)	(9,051)
Sales and transfers of oil and gas produced
during the period	(54,057)	(29,542)	(44,268)	(32,370)
Net change due to extensions, discoveries,
and improved recovery	-	-	-	2,781
Net changes due to purchases and sales of
minerals in place	-	70,993	51,781	(1,912)
Net changes due to revisions in quantity
estimates	57,189	38,206	22,005	16,859
Previously estimated development costs
incurred during the period	17,980	1,758	13,840	16,570
Exchange transaction	-	-	(23,356)	-
Accretion of discount	26,625	16,484	11,179	8,780
Other-unspecified	(12,650)	2,338	(2,065)	1,496
Net change in income taxes	(38,008)	(36,421)	(17,942)	(22,439)
Aggregate change in the standardized measure
of discounted future net cash flows for the year	68,257	169,492	30,256	38,340

End of the period	$ 237,749	$ 169,492	$ 132,732	$ 102,476

The December 31, 2011 amount was estimated by Netherland, Sewell & Associates, Inc. using a twelve month average WTI Cushing price of $96.19 per barrel (bbl), and a Henry Hub gas price of $4.118 per million British Thermal Units, and price differentials. The December 31, 2010 amount was estimated by DeGoyler and MacNaughton and Netherland, Sewell & Associates, Inc. using a twelve month average WTI Cushing price of $79.40 per barrel (bbl), and a Henry Hub gas price of $4.38 per million British Thermal Units, and price differentials.