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Supplemental Information on Oil and Gas Producing Activities (Tables)
 12 Months Ended
Dec. 31, 2012
Supplemental Information on Oil and Gas Producing Activities [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities
Capitalized Costs Relating to Oil and Gas Producing Activities
 
As of December 31,
 
2012
 
2011
 
2010
Proved properties
$
240,217

 
$
277,987

 
$
293,486

Unproved properties
60,746

 
120,288

 
171,303

Wells, equipment and facilities
2,107,061

 
2,081,103

 
1,840,154

Support equipment
6,815

 
6,645

 
6,254

 
2,414,839

 
2,486,023

 
2,311,197

Accumulated depreciation and depletion
(693,123
)
 
(710,948
)
 
(609,380
)
Net capitalized costs
$
1,721,716

 
$
1,775,075

 
$
1,701,817
Costs Incurred in Certain Oil and Gas Activities
Costs Incurred in Certain Oil and Gas Activities
 
Year Ended December 31,
 
2012
 
2011
 
2010
Proved property acquisition costs
$
—

 
$
—

 
$
5,671

Unproved property acquisition costs
27,775

 
47,877

 
133,185

Exploration costs
50,883

 
77,460

 
66,886

Development costs and other
305,693

 
320,263

 
244,092

Total costs incurred
$
384,351

 
$
445,600

 
$
449,834
Production and Sale of Oil and Gas and Non-Cash Charges for Property Impairments
The following table includes results solely from the production and sale of oil and gas and non-cash charges for property impairments. It excludes corporate-related general and administrative expenses and gains or losses on property dispositions. Income tax expense (benefit) is calculated by applying statutory tax rates to revenues after deducting costs and giving effect to oil and gas-related permanent differences and tax credits. 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Revenues
$
310,484

 
$
300,046

 
$
251,336

Production expenses
56,096

 
65,835

 
63,854

Exploration expenses
34,092

 
78,943

 
49,641

Depreciation and depletion expense
204,849

 
160,293

 
130,816

Impairment of oil and gas properties
104,484

 
104,688

 
45,959

 
(89,037
)
 
(109,713
)
 
(38,934
)
Income tax expense (benefit)
(34,724
)
 
(42,788
)
 
(15,184
)
Results of operations
$
(54,313
)
 
$
(66,925
)
 
$
(23,750
)
Net Quantities of Proved Reserves, Including Changes therein and Proved Developed and Proved Undeveloped Reserves
The table on the following page sets forth our net quantities of proved reserves, including changes therein and proved developed and proved undeveloped reserves for the periods presented. This information includes our royalty and net working interest share of the reserves in oil and gas properties. All reserves are located in the United States. Net proved oil, NGL and natural gas reserves for the three years ended December 31, 2012 were estimated by Wright & Company, Inc. utilizing data compiled by us.
 
Oil
 
NGLs
 
Natural
Gas
 
Total
Equivalents
Proved Developed and Undeveloped Reserves
(MBbl)
 
(MBbl)
 
(MMcf)
 
(MBOE)
December 31, 2009
11,517

 
14,870

 
776,665

 
155,831

Revisions of previous estimates 1
(2,410
)
 
7,611

 
(71,421
)
 
(6,702
)
Extensions, discoveries and other additions 2
513

 
3,556

 
90,439

 
19,142

Production
(710
)
 
(671
)
 
(38,919
)
 
(7,867
)
Purchase of reserves
9

 
—

 
3,288

 
557

Sale of reserves in place
(837
)
 
(653
)
 
(15,070
)
 
(4,002
)
December 31, 2010
8,082

 
24,713

 
744,982

 
156,959

Revisions of previous estimates 3
(2,367
)
 
(3,047
)
 
(61,165
)
 
(15,608
)
Extensions, discoveries and other additions 4
9,669

 
732

 
56,345

 
19,792

Production
(1,283
)
 
(907
)
 
(33,410
)
 
(7,758
)
Purchase of reserves
20

 
—

 
1

 
20

Sale of reserves in place
(42
)
 
—

 
(36,840
)
 
(6,182
)
December 31, 2011
14,079

 
21,491

 
669,913

 
147,223

Revisions of previous estimates 5
(439
)
 
(2,495
)
 
(154,372
)
 
(28,662
)
Extensions, discoveries and other additions 6
13,444

 
2,578

 
13,405

 
18,255

Production
(2,252
)
 
(884
)
 
(20,261
)
 
(6,513
)
Purchase of reserves
39

 
1

 
6

 
41

Sale of reserves in place
(20
)
 
—

 
(101,172
)
 
(16,882
)
December 31, 2012
24,851

 
20,691

 
407,519

 
113,462

Proved Developed Reserves:
 

 
 
 
 

 
 

December 31, 2010
4,035

 
10,778

 
412,644

 
83,587

December 31, 2011
7,075

 
9,395

 
330,552

 
71,562

December 31, 2012
10,472

 
8,266

 
169,449

 
46,980

Proved Undeveloped Reserves:
 

 
 
 
 

 
 

December 31, 2010
4,047

 
13,935

 
332,338

 
73,372

December 31, 2011
7,004

 
12,096

 
339,361

 
75,661

December 31, 2012
14,379

 
12,425

 
238,070

 
66,482

1 
We had downward revisions of 6.7 MMBOE primarily as a result of the following: 1) downward revisions of 7.5 MMBOE due to the removal of 200 proved undeveloped locations that would not be developed within five years, 2) upward revisions of 5.7 MMBOE as a result of processing the gas in the Mid-Continent Granite Wash for NGLs, 3) upward revisions of 2.0 MMBOE due to higher prices and 4) various downward revisions for 6.5 MMBOE across our assets as a result of well performance, lease expirations and interest changes.
2 
We added 19.1 MMBOE due to the drilling of 16 wells on locations not classified as proved undeveloped locations in our 2010 year-end reserve report and the addition of 51 new proved undeveloped locations, primarily in East Texas, as a result of our 2011 drilling activities .
3 
We had downward revisions of 15.6 MMBOE primarily as a result of the following: 1) downward revisions of 12.0 MMBOE due to well performance issues, interest changes and economic limits attributable to operating conditions particularly in the Granite Wash, Cotton Valley and Selma Chalk, 2) downward revisions of 1.7 MMBOE due to lower condensate yield in the Granite Wash, 3) downward revisions  of 1.5 MMBOE attributable to the elimination of proved undeveloped locations particularly in the Haynesville Shale in East Texas, 4) downward revisions of 0.8 MMBOE due to lower natural gas prices and 5) upward revisions of 0.5 MMBOE due to higher gas processing yields in the Haynesville Shale and Granite Wash .
4 
We added 19.8 MMBOE due primarily to an increase of 9.0 MMBOE due to the drilling of three Marcellus Shale wells and two Granite Wash wells as well as the addition of 25 proved undeveloped locations in the Marcellus Shale and Selma Chalk. We also drilled 28 Eagle Ford Shale wells and added 26 proved undeveloped locations which resulted in an increase of 10.8 MMBOE .
5 
We had downward revisions of 28.7 MMBOE primarily as a result of the following: 1) downward revisions of 5.0 MMBOE due to well performance issues, interest changes and economic limits due to operating conditions, including lease operating expense and basis differentials, primarily in the Selma Chalk, the Granite Wash, the Cotton Valley, and the Haynesville and Marcellus Shales, 2) downward revisions of 15.0 MMBOE due to lower natural gas prices which significantly reduced the number of proved undeveloped locations in the Marcellus Shale and Selma Chalk and 3) downward revisions of 8.7 MMBOE due to the removal of 38 proved undeveloped locations that would not be developed within five years primarily in the Selma Chalk, the Cotton Valley and the Haynesville Shale.
6 
We added 18.3 MMBOE due primarily to the drilling of 18 wells and the addition of 48 proved undeveloped locations in the Eagle Ford Shale.
Standardized Measure of Discounted Future Net Cash Flows Attributable to Proved Reserves
 
Year Ended December 31,
 
2012
 
2011
 
2010
Future cash inflows
$
4,365,357

 
$
5,032,915

 
$
4,833,030

Future production costs
(1,206,478
)
 
(1,374,658
)
 
(1,388,857
)
Future development costs
(1,118,859
)
 
(1,091,100
)
 
(879,193
)
Future net cash  flows before income tax
2,040,020

 
2,567,157

 
2,564,980

Future income tax expense
(548,132
)
 
(665,751
)
 
(687,928
)
Future net cash flows
1,491,888

 
1,901,406

 
1,877,052

10% annual discount for estimated timing of cash flows
(994,014
)
 
(1,246,910
)
 
(1,235,633
)
Standardized measure of discounted future net cash flows
$
497,874

 
$
654,496

 
$
641,419


Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Sales of oil and gas, net of production costs
$
(254,388
)
 
$
(234,211
)
 
$
(180,568
)
Net changes in prices and production costs
(207,045
)
 
(25,398
)
 
180,316

Extensions, discoveries and other additions
355,495

 
361,284

 
59,729

Development costs incurred during the period
119,706

 
44,741

 
153,563

Revisions of previous quantity estimates
(196,152
)
 
(113,188
)
 
(50,471
)
Purchases of reserves-in-place
1,156

 
308

 
2,239

Sale of reserves-in-place
(116,151
)
 
(37,474
)
 
(47,740
)
Accretion of discount
87,441

 
87,815

 
68,817

Net change in income taxes
25,312

 
16,818

 
(73,332
)
Other changes
28,004

 
(87,618
)
 
4,095

Net increase (decrease)
(156,622
)
 
13,077

 
116,648

Beginning of year
654,496

 
641,419

 
524,771

End of year
$
497,874

 
$
654,496

 
$
641,419