W&T Offshore, Inc. Annual report pursuant to Section 13 and 15(d)

Annual report pursuant to Section 13 and 15(d)

Supplemental Oil And Gas Disclosures (Tables)

Supplemental Oil And Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Oil And Gas Disclosures [Abstract]

Capitalized Costs Related To Oil And Natural Gas


	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

Capitalized Costs Not Subject To Amortization


	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

Cost Incurred In Oil And Gas Property Acquisition Exploration And Development Activities


	Year Ended December 31,
	2011		2010		2009
Costs incurred (1):
Proved property acquisitions	$	369.9	$	277.3	$	17.5
Development		203.7		158.3		142.9
Exploration (2) (3)		92.7		70.8		101.6
Unproved property acquisitions (4)		95.1		19.7		12.2

Total costs incurred in oil and gas property acquisition, exploration and development activities	$	761.4	$	526.1	$	274.2

(1)	Includes additions (reductions) to our ARO of $32.8 million, $106.1 million and ($6.0) million during the years 2011, 2010 and 2009, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. Refer to Note 5.

(2)	Includes seismic costs of $8.0 million, $5.8 million and $6.6 million incurred during the years 2011, 2010 and 2009, respectively.

(3)	Includes geological and geophysical costs charged to expense of $6.8 million, $4.3 million and $4.1 million during the years 2011, 2010 and 2009, respectively.

(4)	The amounts for 2011, 2010 and 2009 include capitalized interest associated with properties classified as unproved at December 31, 2011, 2010 and 2009, respectively.

Schedule Of Depreciation, Depletion, Amortization And Accretion Expense


	Year Ended December 31,
	2011		2010		2009
Depreciation, depletion, amortization and accretion per Mcfe	$	3.24	$	3.38	$	3.61

Schedule Of Oil And Natural Gas 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).

Schedule Of Prices Weighted By Field Production Related To The Proved Reserves


	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

Schedule Of Changes In Standardized Measure


	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

- Definition

Tabular disclosure of aggregate capitalized costs relating to an enterprise's oil and gas producing activities and the aggregate related accumulated depreciation, depletion, amortization, and valuation allowances.

+ References + Details

- Definition

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

+ References + Details

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details