Note 16 — Supplemental Oil and Gas Disclosures (Unaudited)

As previously disclosed, we sold ERT on February 6, 2013. The following oil and gas disclosures concerning our costs and estimated proved reserves are required and provided for your information as we continued to own the oil and gas properties at December 31, 2012. Our only remaining involvement in the oil and gas business is the substantially-abandoned Camelot field in the U.K. (Note 3) and our remaining overriding royalty interest in the Wang well (Green Canyon Block 237) and certain other future exploration prospects.

Capitalized Costs

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


		2012		2011

Unproved oil and gas properties	$	51,513	$	50,389
Proved oil and gas properties		2,453,667		2,516,363
Total oil and gas properties		2,505,180		2,566,752
Accumulated depletion, depreciation and amortization		(1,717,314)		(1,695,105)
Net capitalized costs	$	787,866	$	871,647

Included in the depreciable basis of our proved oil and gas properties is the estimate of our proportionate share of asset retirement obligations relating to these properties which are also reflected as asset retirement obligations within our non-current liabilities of discontinued operations (Note 3). At December 31, 2012 and 2011, our oil and gas asset retirement obligations totaled $203.9 million and $254.4 million, respectively.

Costs Incurred in Oil and Gas Producing Activities

The following table reflects the costs incurred in oil and gas property acquisition and development activities, including estimated asset retirement obligations, during the years indicated (in thousands):


		Year Ended December 31,
		2012		2011		2010

Property acquisition costs:
Proved properties	$	-	$	-	$	-
Unproved properties		-		41		364
Total property acquisition costs		-		41		364
Exploration costs		135,311		2,513		1,362
Development costs ⁽¹⁾		17,344		126,196		53,002
Asset retirement costs ⁽²⁾		59,715		46,446		25,356
Total costs incurred	$	212,370	$	175,196	$	80,084

(1) Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells.

(2) Asset retirement costs include $15.5 million, $20.0 million, $0.9 million, respectively, associated with the Camelot field in the United Kingdom during the years ended December 31, 2012, 2011 and 2010.

Estimated Quantities of Proved Oil and Gas Reserves

We have employed full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. ERT’s Vice President — Reservoir Engineering and Business Development, our internal reservoir engineers and geologists analyzed 100% of our significant United States oil and gas fields (40 fields as of December 31, 2012). We consider any field with discounted future net revenues of 1% or greater of the total discounted future net revenues of all our fields to be significant.

We used our internal estimates of proved reserves for the related disclosures at December 31, 2012. The reports to estimate our proved reserves at December 31, 2011 and 2010 were prepared by an independent reservoir engineering firm.

The following table presents our net ownership interest in proved oil reserves (MBbls) and proved gas reserves, including natural gas liquids (MMcf):


			Total
	Oil	Gas	(MBOE)

Total proved reserves at December 31, 2009 ⁽¹⁾	29,727	399,315	96,280
Revision of previous estimates ^{(1), (2)}	(1,555)	(144,954)	(25,714)
Production	(3,354)	(27,097)	(7,870)
Purchases of reserves in place	-	-	-
Sales of reserves in place	-	-	-
Extensions and discoveries	-	-	-
Total proved reserves at December 31, 2010	24,818	227,264	62,696
Revision of previous estimates ⁽³⁾	3,475	(108,947)	(14,683)
Production	(5,785)	(17,458)	(8,694)
Purchases of reserves in place	-	-	-
Sales of reserves in place	(205)	(4,109)	(890)
Extensions and discoveries	386	271	431
Total proved reserves at December 31, 2011	22,689	97,021	38,860
Revision of previous estimates ⁽⁴⁾	647	(12,926)	(1,508)
Production	(4,725)	(11,361)	(6,619)
Purchases of reserves in place	-	-	-
Sales of reserves in place	(75)	(3,473)	(654)
Extensions and discoveries	1,434	4,026	2,105
Total proved reserves at December 31, 2012	19,970	73,287	32,184

Total proved developed reserves as of:
December 31, 2009	14,850	124,763	35,644
December 31, 2010	11,796	75,664	24,407
December 31, 2011	12,754	59,859	22,731
December 31, 2012	12,431	43,475	19,677

(1) Total proved gas reserves at December 31, 2009 include 12 Bcf associated with the Camelot field in the United Kingdom. The U.K. reserves were reversed in 2010 as a result of our decision to no longer develop the field and to pursue its full abandonment.

(2) Includes an approximate 1.8 MMBbls decrease in oil reserve and an approximate 131 Bcf decrease in gas reserve as reflected in our independent petroleum engineer reserve report at June 30, 2010 resulting from a combination of factors, including well performance issues at certain producing fields, most notably the Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest all or a portion of our oil and gas assets and the increasing uncertainties about future oil and gas operations in the Gulf of Mexico as a result of the Macondo well control incident.

(3) The positive revision in oil reserves reflects the better than expected production volumes primarily from the Phoenix field at Green Canyon Blocks 236, 237, 238 and 282 since it began production in October 2010. The decrease in gas reserve primarily represents a reclassification of estimated proved reserves to the probable reserve category following the receipt and interpretation of new seismic data. The field with the largest shift from the proved to probable reserve category was the Bushwood field, where we reclassified approximately 87 Bcf at December 31, 2011.

(4) Decrease primarily represents revisions at several gas fields due to well performance and future capital investment plans.

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

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


		United		United
		States		Kingdom		Total
As of December 31, 2012 —
Future cash inflows	$	2,341,354	$	-	$	2,341,354
Future costs:
Production		509,408		-		509,408
Development and abandonment		507,074		2,897		509,971
Total future costs		1,016,482		2,897		1,019,379
Future net cash flows before income taxes		1,324,872		(2,897)		1,321,975
Future income tax expense		330,630		-		330,630
Future net cash flows		994,242		(2,897)		991,345
Discount at 10% annual rate		153,032		-		153,032
Standardized measure of discounted future net cash flows	$	841,210	$	(2,897)	$	838,313


As of December 31, 2011 —
Future cash inflows	$	2,811,956	$	-	$	2,811,956
Future costs:
Production		419,617		-		419,617
Development and abandonment		557,323		27,300		584,623
Total future costs		976,940		27,300		1,004,240
Future net cash flows before income taxes		1,835,016		(27,300)		1,807,716
Future income tax expense		477,630		-		477,630
Future net cash flows		1,357,386		(27,300)		1,330,086
Discount at 10% annual rate		266,954		-		266,954
Standardized measure of discounted future net cash flows	$	1,090,432	$	(27,300)	$	1,063,132


As of December 31, 2010 —
Future cash inflows	$	2,925,744	$	-	$	2,925,744
Future costs:
Production		583,050		-		583,050
Development and abandonment		590,870		12,200		603,070
Total future costs		1,173,920		12,200		1,186,120
Future net cash flows before income taxes		1,751,824		(12,200)		1,739,624
Future income tax expense		430,153		-		430,153
Future net cash flows		1,321,671		(12,200)		1,309,471
Discount at 10% annual rate		318,404		-		318,404
Standardized measure of discounted future net cash flows	$	1,003,267	$	(12,200)	$	991,067

Future cash inflows are computed by applying the appropriate average 12-month commodity prices as based on the price of oil and natural gas on the first day of each month during the year, adjusted for location and quality differentials on a property-by-property basis, 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,
		2012		2011		2010

Oil price per Bbl	$	104.85	$	105.35	$	77.55
Natural gas price per Mcf	$	3.38	$	4.34	$	4.40

The future income tax expense was computed by applying the appropriate year-end statutory rates, with consideration of future tax rates already legislated, to the future pretax net cash flows less the tax basis of the associated properties. 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 assumed. 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 and gas reserves are as follows (in thousands):


		Year Ended December 31,
		2012		2011		2010

Standardized measure, beginning of year	$	1,063,132	$	991,067	$	991,060
Changes during the year:
Sales, net of production costs		(379,910)		(516,895)		(294,212)
Net change in prices and production costs		(242,037)		414,426		577,687
Changes in future development costs		(65,854)		(108,007)		84,907
Development costs incurred ⁽¹⁾		149,702		168,005		55,646
Accretion of discount		147,157		131,464		129,083
Net change in income taxes		101,720		(54,613)		(41,115)
Purchases of reserves in place		-		-		-
Extensions and discoveries		110,655		29,479		-
Sales of reserves in place		(6,096)		(14,324)		-
Net change due to revision in quantity estimates		28,627		(186,197)		(422,987)
Changes in production rates (timing) and other		(68,783)		208,727		(89,002)
Total		(224,819)		72,065		7
Standardized measure, end of year	$	838,313	$	1,063,132	$	991,067