21. Supplemental Oil and Gas Disclosures – UNAUDITED

Geographic Area of Operation

All of our proved reserves are located within the United States, with a majority of those reserves located in the Gulf of Mexico and a minority located in Texas. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis.

Capitalized Costs

Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):


	December 31,
	2012			2011			2010
Net capitalized cost:
Proved oil and natural gas properties and equipment	$	6,551.5		$	5,775.4		$	5,130.9
Unproved oil and natural gas properties and equipment		143.0			183.6			94.7
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities		(4,640.8	)		(4,307.1	)		(4,009.9	)

Net capitalized costs related to producing activities	$	2,053.7		$	1,651.9		$	1,215.7

Costs Not Subject To Amortization

Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years. The following table provides a summary of costs that are not being amortized as of December 31, 2012, by the year in which the costs were incurred (in millions):


	Total		2012		2011		2010		Prior to 2010
Costs excluded by year incurred:
Acquisition costs	$	99.8	$	13.1	$	67.4	$	—	$	19.3
Capitalized interest not subject to amortization		23.7		9.1		6.1		2.1		6.4

Total costs not subject to amortization	$	123.5	$	22.2	$	73.5	$	2.1	$	25.7

Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities

The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions):


	Year Ended December 31,
	2012		2011		2010
Costs incurred (1):
Proved property acquisitions	$	239.8	$	369.9	$	277.3
Exploration (2) (3)		151.3		92.7		70.8
Development		363.7		203.7		158.3
Unproved property acquisitions (4)		26.5		95.1		19.7

Total costs incurred in oil and gas property acquisition, exploration and development activities	$	781.3	$	761.4	$	526.1

(1)	Includes additions (reductions) to our ARO of $86.9 million, $32.8 million and $106.1 million during 2012, 2011 and 2010, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. Refer to Note 5.

(2)	Includes seismic costs of $6.2 million, $8.0 million and $5.8 million incurred during 2012, 2011 and 2010, respectively.

(3)	Includes geological and geophysical costs charged to expense of $6.2 million, $6.8 million and $4.3 million during 2012, 2011 and 2010, respectively.

(4)	The amounts for 2012, 2011 and 2010 include capitalized interest associated with properties classified as unproved at December 31, 2012, 2011 and 2010, respectively.

Depreciation, depletion, amortization and accretion expense

The following table presents our depreciation, depletion, amortization and accretion expense per million cubic feet equivalent (“Mcfe”) of products sold.


	Year Ended December 31,
	2012		2011		2010
Depreciation, depletion, amortization and accretion per Mcfe	$	3.47	$	3.24	$	3.38

Oil and Natural Gas Reserve Information

There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represent estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. We are not the operator with respect to approximately 14% of our proved developed non-producing reserves, so we may not be in a position to control the timing of all development activities.

The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States and the majority of the reserves are located in the Gulf of Mexico. These reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information.


										Total Equivalent Reserves
	Oil (MMBbls) (1)			NGLs (MMBbls) (1)			Natural Gas (Bcf) (1)			Oil Equivalent (MMBoe) (2)			Natural Gas Equivalent (Bcfe) (2)
Proved reserves as of December 31, 2009		31.2			3.0			165.8			61.8			371.0
Revisions of previous estimates (3)		(0.2	)		1.2			14.6			3.4			20.2
Extensions and discoveries (4)		1.2			0.5			19.1			4.9			29.2
Purchase of minerals in place (5)		7.7			0.7			101.5			25.3			152.0
Production		(5.9	)		(1.2	)		(44.7	)		(14.5	)		(87.0	)

Proved reserves as of December 31, 2010		34.0			4.2			256.3			80.9			485.4
Revisions of previous estimates (6)		0.8			5.5			13.5			8.6			51.1
Extensions and discoveries (7)		2.0			0.4			17.7			5.3			32.0
Purchase of minerals in place (8)		20.7			8.9			55.9			39.0			234.1
Production		(6.1	)		(1.9	)		(53.7	)		(16.9	)		(101.5	)

Proved reserves as of December 31, 2011		51.4			17.1			289.7			116.9			701.1
Revisions of previous estimates (9)		(1.1	)		(2.6	)		(4.8	)		(4.6	)		(27.5	)
Extensions and discoveries (10)		8.2			2.6			29.6			15.7			94.5
Purchase of minerals in place (11)		2.5			0.2			25.5			7.0			42.0
Sales of reserves (12)		(0.2	)		—			(1.1	)		(0.4	)		(2.2	)
Production		(6.0	)		(2.1	)		(53.8	)		(17.1	)		(102.8	)

Proved reserves as of December 31, 2012		54.8			15.2			285.1			117.5			705.1

Year-end proved developed reserves:
2012		35.3			11.0			243.5			86.9			521.2
2011		23.4			11.0			251.4			76.4			458.2
2010		23.6			3.4			229.1			65.2			391.3

Year-end proved undeveloped reserves:
2012		19.5			4.2			41.6			30.6			183.9
2011		28.0			6.1			38.3			40.5			242.9
2010		10.4			0.8			27.2			15.7			94.1

(1)	Estimated reserves as of December 31, 2012, 2011, 2010 and 2009 are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for those years in accordance with current definitions and guidelines set forth by the SEC and the FASB.

(2)

The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly.

(3)	Includes revisions due to price of 17.5 Bcfe.

(4)	Includes discoveries of 21.9 Bcfe primarily in the Main Pass 108, Main Pass 98 and Main Pass 283 fields and extensions of 7.2 Bcfe primarily in the Main Pass 283 field.

(5)	Primarily due to the acquisition of the Total Properties and the Tahoe Properties.

(6)

Includes revision of 6.3 Bcfe due to an increase in average prices; 16.5 Bcfe for a change in NGLs marketing arrangements; 11.3 Bcfe increase due to additional compression at our Tahoe field that increases production and ultimate recoveries; and 10.6 Bcfe at our Fairway field for revisions to reserve estimates from the acquisition date to year end.

(7)	Includes discoveries of 13.9 Bcfe at our Main Pass 98 field and 8.0 Bcfe at our Ship Shoal 349/359 field and extensions of 3.7 Bcfe at our Main Pass 108 field.

(8)	Primarily due to the acquisition of the Yellow Rose Properties and the Fairway Properties.

(9)	Includes downward revisions due to price of 8.0 Bcfe and negative performance revisions of 17.9 Bcfe at our Yellow Rose Properties.

(10)	Includes extensions and discoveries of 69.5 Bcfe at our Yellow Rose Properties and extensions and discoveries of 16.2 Bcfe at our High Island 22 field.

(11)	Due to the acquisition of the Newfield Properties.

(12)	Due to the sale of our interest in the South Timbalier 41 field.

Volume measurements:


Mcf – thousand cubic feet		Bbl – barrel
Bcf – billion cubic feet		MMBbls – million barrels for crude oil, condensate or NGLs
Bcfe – billion cubic feet equivalent		MMBoe – million barrels of oil equivalent

Standardized Measure of Discounted Future Net Cash Flows

The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein, as defined by the FASB. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for December 31, 2012, 2011, 2010 and 2009. All prices are adjusted by lease for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio is applied to the oil price using FASB/SEC guidance. The average commodity prices weighted by field production related to the proved reserves are as follows:


	December 31,
	2012		2011		2010		2009
Oil – per barrel	$	98.13	$	97.36	$	76.28	$	55.87
NGLs – per barrel		47.30		51.30		44.92		33.36
Natural gas – per Mcf		2.77		4.11		4.57		3.80

Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2013 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in thousands):


	Year Ended December 31,
	2012			2011			2010
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows	$	6,888,431		$	7,077,206		$	3,953,655
Future costs:
Production		(1,858,282	)		(1,862,488	)		(1,011,552	)
Development		(655,406	)		(543,017	)		(243,570	)
Dismantlement and abandonment		(508,051	)		(513,620	)		(520,490	)
Income taxes		(1,002,127	)		(1,126,573	)		(495,696	)

Future net cash inflows before 10% discount		2,864,565			3,031,508			1,682,347
10% annual discount factor		(1,018,188	)		(1,025,131	)		(503,275	)

	$	1,846,377		$	2,006,377		$	1,179,072


	Year Ended December 31,
	2012			2011			2010
Changes in Standardized Measure
Standardized measure, beginning of year	$	2,006,377		$	1,179,072		$	660,396
Increases (decreases):
Sales and transfers of oil and gas produced, net of production costs		(620,437	)		(729,574	)		(521,551	)
Net changes in price, net of future production costs		(224,260	)		634,174			367,575
Extensions and discoveries, net of future production and development costs		181,870			219,924			143,612
Changes in estimated future development costs		(103,320	)		(4,572	)		(59,124	)
Previously estimated development costs incurred		332,939			173,911			97,188
Revisions of quantity estimates		(128,075	)		204,988			94,735
Accretion of discount		231,144			135,791			68,862
Net change in income taxes		99,684			(398,204	)		(221,226	)
Purchases of reserves in-place		270,168			483,286			624,302
Sales of reserves in-place		(16,105	)		—			—
Changes in production rates due to timing and other		(183,608	)		107,581			(75,697	)

Net increase (decrease) in standardized measure		(160,000	)		827,305			518,676

Standardized measure, end of year	$	1,846,377		$	2,006,377		$	1,179,072