22. 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,
		2011				2010				2009
Net capitalized cost:
Proved oil and natural gas properties and equipment		$	5,775.4			$	5,130.9			$	4,637.2
Unproved oil and natural gas properties and equipment			183.6				94.7				95.5
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities			(4,307.1	)			(4,009.9	)			(3,743.3	)
Net capitalized costs related to producing activities		$	1,651.9			$	1,215.7			$	989.4

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, 2011, by the year in which the costs were incurred (in millions):

 

		Total				2011				2010				2009				Prior to 2009
Costs excluded by year incurred:
Acquisition costs		$	125.7			$	81.3			$	—			$	—			$	44.4
Capitalized interest not subject to amortization			28.8				9.6				4.8				4.2				10.2
Total costs not subject to amortization		$	154.5			$	90.9			$	4.8			$	4.2			$	54.6

 

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):

 

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,
		2011				2010				2009
Depreciation, depletion, amortization and accretion per Mcfe		$	3.24			$	3.38			$	3.61

Oil and Natural Gas Reserve Information

Effective for our annual reporting period ended December 31, 2009, we adopted certain amendments to the Extractive Activities – Oil and Gas topic of the Codification that updated and aligned the FASB's reserve estimation and disclosure requirements for oil and natural gas companies with the reserve estimation and disclosure requirements that were adopted by the SEC in December 2008. In accordance with the new rules, we use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period commodity prices, when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test impairment were changed from end-of-period commodity prices to the 12-month average commodity prices. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years. As the rules are effective for December 31, 2009 and were not applied retroactively, the data for 2008 may not be comparable to the data for 2009, 2010 and 2011. In addition to the oil and gas reserve information, the amendments impacted our financial position and the results of operations as they affected our determination of DD&A expense and the calculations used in determining impairment under the ceiling test rules. The amendments did not have an impact to our cash flows.

For the year 2009, the following items were affected by the change in the rules. The initial application of these rules resulted in the removal of 3.9 million barrels of oil equivalent ("MMBoe") (23.2 billion cubic feet equivalent ("Bcfe")) in the year 2009 of proved undeveloped reserves associated with two of our fields for which our plan of development was not within five years from when the reserves were initially recorded, as required. The impact on our DD&A expense for 2009 related to the adoption of these amendments to the Codification was an approximate $7.6 million ($0.08 per Mcfe) increase in DD&A.

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 data 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 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 10% 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 (including natural gas liquids) and natural gas reserves, virtually all of which are located offshore 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, 2008			40.0				3.9				227.9				81.9				491.1
Revisions of previous estimates (3)			(2.1	)			—				(13.0	)			(4.3	)			(25.4	)
Extensions and discoveries (4)			1.2				0.3				14.5				3.9				23.4
Purchase of minerals in place			—				—				0.4				0.1				0.7
Sales of reserves (5)			(1.8	)			(0.1	)			(12.4	)			(4.0	)			(24.0	)
Production			(6.1	)			(1.1	)			(51.6	)			(15.8	)			(94.8	)
Proved reserves as of December 31, 2009			31.2				3.0				165.8				61.8				371.0
Revisions of previous estimates (6)			(0.2	)			1.2				14.6				3.4				20.2
Extensions and discoveries (7)			1.2				0.5				19.1				4.9				29.2
Purchase of minerals in place (8)			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 (9)			0.8				5.5				13.5				8.6				51.1
Extensions and discoveries (10)			2.0				0.4				17.7				5.3				32.0
Purchase of minerals in place (11)			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
Year-end proved developed reserves:
2011			23.4				11.0				251.4				76.4				458.2
2010			23.6				3.4				229.1				65.2				391.3
2009			21.3				2.4				141.3				47.3				283.5
Year-end proved undeveloped reserves:
2011			28.0				6.1				38.3				40.5				242.9
2010			10.4				0.8				27.2				15.7				94.1
2009			9.9				0.6				24.5				14.5				87.5

(1)

Estimated reserves as of December 31, 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. Estimated of reserves as of December 31, 2008 were based on end-of-year prices.

(2)

Bcfe and MMBoe are determined using the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price per Mcfe for oil and NGLs may differ significantly from the price per Mcf for natural gas. Similarly, the price per Bbl for oil for may differ significantly from the price per Bbl for NGLs.

(3)

Revisions for 2009 included decreases attributable to revised reserve reporting requirements for oil and natural gas companies enacted by the SEC and the FASB, which became effective for annual reporting periods ending on or after December 31, 2009. The initial application of these rules resulted in the removal of 23.2 Bcfe of proved undeveloped reserves associated with two of our fields for which our plan of development was not within five years from when the reserves were initially recorded, as required. Also included in the revisions of previous estimates for 2009 are negative revisions of 4.7 Bcfe due to performance.

(4)	The majority of these volumes are attributable to extensions and discoveries resulting from our participation in the drilling of eight successful exploratory wells in 2009, all of which were on the conventional shelf.

(5)	In the second quarter of 2009, we sold one of our fields in Louisiana state waters, and in the fourth quarter of 2009, we sold 36 non-core oil and natural gas fields in the Gulf of Mexico, subject to the terms of the purchase and sale agreements.

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

(7)	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.

(8)	Primarily due to the properties acquired from Total (Matterhorn and Virgo fields) and the properties acquired from Shell (Tahoe, Southeast Tahoe and Droshky fields).

(9)

Includes revision of 6.3 Bcfe due to an increase in average prices, 16.5 Bcfe for a change in NGLs marketing arrangements that allow us to recover a greater percentage of our NGLs from the gas stream, 11.3 Bcfe increase due to additional compression at our Tahoe field that allows us to reduce the drawdown pressure that increases production and ultimate recoveries, and 10.6 Bcfe at Fairway for revisions to reserve estimates from the acquisition date to year end.

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

(11)	Primarily due to the properties acquired from Opal (the Yellow Rose Properties) and the properties acquired from Shell (the Fairway Properties).

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, 2011, 2010 and 2009 and period-end commodity prices for December 31, 2008 (beginning of 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,
		2011				2010				2009				2008
Oil – per barrel		$	97.36			$	76.28			$	55.87			$	38.85
NGLs – per barrel			51.30				44.92				33.36				25.90
Natural gas – per Mcf			4.11				4.57				3.80				6.17

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 2012 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,
		2011				2010				2009
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows		$	7,077,206			$	3,953,655			$	2,474,260
Future costs:
Production			(1,862,488	)			(1,011,552	)			(604,794	)
Development			(543,017	)			(243,570	)			(212,835	)
Dismantlement and abandonment			(513,620	)			(520,490	)			(496,540	)
Income taxes			(1,126,573	)			(495,696	)			(186,101	)
Future net cash inflows before 10% discount			3,031,508				1,682,347				973,990
10% annual discount factor			(1,025,131	)			(503,275	)			(313,594	)
		$	2,006,377			$	1,179,072			$	660,396
		Year Ended December 31,
		2011				2010				2009
Changes in Standardized Measure
Standardized measure, beginning of year		$	1,179,072			$	660,396			$	761,682
Increases (decreases):
Sales and transfers of oil and gas produced, net of production costs			(729,574	)			(521,551	)			(386,331	)
Net changes in price, net of future production costs			634,174				367,575				(34,841	)
Extensions and discoveries, net of future production and development costs			219,924				143,612				98,087
Changes in estimated future development costs			(4,572	)			(59,124	)			144,590
Previously estimated development costs incurred			173,911				97,188				224,802
Revisions of quantity estimates			204,988				94,735				(86,600	)
Accretion of discount			135,791				68,862				78,789
Net change in income taxes			(398,204	)			(221,226	)			(32,394	)
Purchases of reserves in-place			483,286				624,302				(9,927	)
Sales of reserves in-place			—				—				(205,691	)
Changes in production rates due to timing and other			107,581				(75,697	)			108,230
Net increase (decrease) in standardized measure			827,305				518,676				(101,286	)
Standardized measure, end of year		$	2,006,377			$	1,179,072			$	660,396