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Supplemental Oil and Natural Gas Disclosures (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Cost incurred in oil and natural gas activities
Costs incurred in oil and natural gas activities were as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Property acquisitions:
 
 
 
 
 
 
Proved
 
$
491,041

 
$
86,465

 
$
3,373,450

Unevaluated
 
115,270

 
17,858

 
1,297,695

Exploration
 
12,019

 
31,483

 
8,728

Development
 
1,111,314

 
1,144,243

 
658,758

Total costs incurred (1)
 
$
1,729,644

 
$
1,280,049

 
$
5,338,631


(1)
Capitalized general and administrative costs that directly relate to exploration and development activities were $49.2 million, $35.0 million and $20.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Results of operations from oil and natural gas producing activities excluding corporate overhead and interest costs
Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:
 
 
Year Ended December 31,
In thousands, except per BOE data
 
2012
 
2011
 
2010
Oil, natural gas, and related product sales
 
$
2,409,867

 
$
2,269,151

 
$
1,793,292

Lease operating costs
 
532,359

 
507,397

 
470,364

Marketing expenses
 
52,836

 
26,047

 
31,036

Taxes other than income
 
149,919

 
138,419

 
114,569

Depletion, depreciation and amortization
 
448,424

 
369,075

 
391,782

CO2 properties and pipelines depletion and depreciation (1)
 
42,064

 
24,460

 
29,206

Commodity derivatives expense (income)
 
(4,834
)
 
(52,497
)
 
(21,414
)
Net operating income
 
1,189,099

 
1,256,250

 
777,749

Income tax provision
 
457,803

 
477,375

 
295,545

Results of operations from oil and natural gas producing activities
 
$
731,296

 
$
778,875

 
$
482,204

 
 
 
 
 
 
 
Depletion, depreciation and amortization per BOE
 
$
18.69

 
$
16.42

 
$
15.82


(1)
Represents an allocation of the depletion, depreciation and amortization of our CO2 properties and pipelines associated with our tertiary oil producing activities.
Estimated quantities of reserves
Estimated Quantities of Proved Reserves
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
 
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
Balance at beginning of year
 
357,733

 
625,208

 
461,934

 
338,276

 
357,893

 
397,925

 
192,879

 
87,975

 
207,542

Revisions of previous estimates
 
(7,099
)
 
(16,720
)
 
(9,886
)
 
(4,478
)
 
(14,058
)
 
(6,821
)
 
3,538

 
16,171

 
6,233

Revisions due to price changes
 
(401
)
 
(37,969
)
 
(6,729
)
 
2,558

 
485

 
2,639

 
2,780

 
811

 
2,915

Extensions and discoveries
 
14,910

 
10,005

 
16,579

 
42,936

 
52,339

 
51,658

 
26,313

 
130,245

 
48,021

Improved recovery (1)
 
69,543

 
—

 
69,543

 
264

 
—

 
264

 
30,173

 
—

 
30,173

Production

 
(24,462
)
 
(10,654
)
 
(26,238
)
 
(22,169
)
 
(10,783
)
 
(23,966
)
 
(21,870
)
 
(28,491
)
 
(26,619
)
Acquisition of minerals in place
 
24,677

 
20,598

 
28,110

 
346

 
239,332

 
40,235

 
155,021

 
622,984

 
258,852

Sales of minerals in place
 
(105,777
)
 
(108,827
)
 
(123,915
)
 
—

 
—

 
—

 
(50,558
)
 
(471,802
)
 
(129,192
)
Balance at end of year
 
329,124

 
481,641

 
409,398

 
357,733

 
625,208

 
461,934

 
338,276

 
357,893

 
397,925

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
 
239,741

 
125,970

 
260,736

 
219,077

 
110,516

 
237,496

 
116,192

 
69,513

 
127,778

Balance at end of year
 
236,009

 
64,191

 
246,708

 
239,741

 
125,970

 
260,736

 
219,077

 
110,516

 
237,496


(1)
Improved recovery reflects reserve additions which result from the application of secondary recovery methods such as water flooding, or tertiary recovery methods such as CO2 flooding.  In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO2 injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.
Oil and natural gas prices
The following representative oil and natural gas prices were used in the Standardized Measure.  These prices were adjusted by field to arrive at the appropriate corporate net price.
 
 
December 31,
 
 
2012
 
2011
 
2010
Oil (NYMEX)
 
$
94.71

 
$
96.19

 
$
79.43

Natural Gas (Henry Hub)
 
2.85

 
4.16

 
4.40
Discounted future net cash inflows after income taxes
 
 
December 31,
In thousands
 
2012
 
2011
 
2010
Future cash inflows
 
$
34,779,549

 
$
38,165,122

 
$
26,698,819

Future production costs
 
(13,114,740
)
 
(12,570,015
)
 
(9,702,896
)
Future development costs
 
(2,034,174
)
 
(3,026,898
)
 
(1,912,457
)
Future income taxes
 
(6,672,857
)
 
(7,379,972
)
 
(4,700,023
)
Future net cash flows
 
12,957,778

 
15,188,237

 
10,383,443

10% annual discount for estimated timing of cash flows
 
(6,543,398
)
 
(8,180,632
)
 
(5,465,516
)
Standardized measure of discounted future net cash flows
 
$
6,414,380

 
$
7,007,605

 
$
4,917,927
Analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Beginning of year
 
$
7,007,605

 
$
4,917,927

 
$
2,457,385

Sales of oil and natural gas produced, net of production costs
 
(1,673,253
)
 
(1,597,288
)
 
(1,177,322
)
Net changes in sales prices
 
(584,526
)
 
4,646,086

 
2,062,181

Extensions and discoveries, less applicable future development and production costs
 
291,558

 
762,370

 
295,074

Improved recovery (1)
 
1,901,109

 
15,708

 
623,622

Previously estimated development costs incurred
 
376,199

 
354,228

 
193,947

Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production
 
(797,975
)
 
(1,673,283
)
 
(285,158
)
Accretion of discount
 
875,383

 
729,234

 
307,546

Acquisition of minerals in place
 
767,267

 
29,737

 
3,671,439

Sales of minerals in place
 
(1,805,309
)
 
—

 
(1,474,443
)
Net change in income taxes
 
56,322

 
(1,177,114
)
 
(1,756,344
)
End of year
 
$
6,414,380

 
$
7,007,605

 
$
4,917,927


(1)
Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.