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Supplemental Gas Data (Tables)
 12 Months Ended
Dec. 31, 2013
SUPPLEMENTAL GAS DATA: [Abstract]  
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]
The standardized measure is intended to provide a better means for comparing the value of CONSOL Energy's proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.
 
 
December 31,
 
 
2013
 
2012
 
2011
Future Cash Flows:
 
 
 
 
 
 
Revenues
 
$
21,602,594

 
$
11,777,550

 
$
14,804,398

Production costs
 
(7,105,962
)
 
(4,823,670
)
 
(5,262,635
)
Development costs
 
(3,902,875
)
 
(2,450,589
)
 
(1,674,829
)
Income tax expense
 
(4,025,626
)
 
(1,711,251
)
 
(2,989,435
)
Future Net Cash Flows
 
6,568,131

 
2,792,040

 
4,877,499

Discounted to present value at a 10% annual rate
 
(4,887,320
)
 
(2,055,834
)
 
(3,130,318
)
Total standardized measure of discounted net cash flows
 
$
1,680,811

 
$
736,206

 
$
1,747,181

The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
 
 
December 31,
 
 
2013
 
2012
 
2011
Balance at beginning of period
 
$
736,206

 
$
1,747,181

 
$
1,660,821

Net changes in sales prices and production costs
 
1,295,956

 
(1,480,573
)
 
(339,098
)
Sales net of production costs
 
(365,477
)
 
(104,518
)
 
(217,186
)
Net change due to revisions in quantity estimates
 
132,900

 
(104,158
)
 
(83,580
)
Net change due to extensions, discoveries and improved recovery
 
383,308

 
14,645

 
324,755

Net change due to (divestiture) acquisition
 
—

 
—

 
(559,132
)
Development costs incurred during the period
 
625,824

 
333,640

 
463,401

Difference in previously estimated development costs compared to actual costs incurred during the period
 
(123,976
)
 
(96,749
)
 
154,137

Changes in estimated future development costs
 
(486,518
)
 
(153,104
)
 
155,619

Net change in future income taxes
 
(578,951
)
 
619,045

 
130,746

Accretion of discount and other
 
61,539

 
(39,203
)
 
56,698

     Total discounted cash flow at end of period
 
$
1,680,811

 
$
736,206

 
$
1,747,181
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
Capitalized Costs:
 
 
As of December 31,
 
 
2013
 
2012
Proven properties
 
$
1,670,404

 
$
1,596,838

Unproven properties
 
1,463,406

 
1,266,017

Intangible drilling costs
 
1,937,336

 
1,550,297

Wells and related equipment
 
688,548

 
492,364

Gathering assets
 
1,058,008

 
1,006,882

Gas Well Plugging
 
113,481

 
70,753

Total Property, Plant and Equipment
 
6,931,183

 
5,983,151

Accumulated Depreciation, Depletion and Amortization
 
(1,187,409
)
 
(959,291
)
Net Capitalized Costs
 
$
5,743,774

 
$
5,023,860
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]
Costs incurred for property acquisition, exploration and development (*):
 
 
For the Years Ended December 31,
 
 
2013
 
2012
 
2011
Property acquisitions
 
 
 
 
 
 
Proven properties
 
$
—

 
$
50,005

 
$
6,673

Unproven properties
 
260,477

 
28,634

 
58,731

Development
 
629,100

 
339,608

 
463,401

Exploration
 
95,413

 
130,312

 
131,419

Total
 
$
984,990

 
$
548,559

 
$
660,224

__________
(*)
Includes costs incurred whether capitalized or expensed.
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]
Results of Operations for Producing Activities:
 
 
For the Years Ended December 31,
 
 
2013
 
2012
 
2011
Production Revenue
 
$
740,869

 
$
660,442

 
$
751,767

Royalty Interest Gas Revenue
 
63,202

 
49,405

 
66,929

Purchased Gas Revenue
 
6,531

 
3,316

 
4,344

Total Revenue
 
810,602

 
713,163

 
823,040

Lifting Costs
 
96,600

 
90,835

 
106,477

Ad Valorem, Severance & Other Taxes
 
28,677

 
26,145

 
26,261

Gathering Costs
 
201,023

 
160,575

 
142,339

Royalty Interest Gas Costs
 
53,069

 
38,922

 
59,377

Direct Administrative, Selling & Other Costs
 
49,092

 
47,567

 
60,355

Other Costs
 
61,119

 
39,029

 
18,095

Purchased Gas Costs
 
4,837

 
2,711

 
3,831

DD&A
 
229,562

 
202,956

 
206,821

Total Costs
 
723,979

 
608,740

 
623,556

Pre-tax Operating Income
 
86,623

 
104,423

 
199,484

Income Taxes
 
32,917

 
39,827

 
79,873

Results of Operations for Producing Activities excluding Corporate and Interest Costs
 
$
53,706

 
$
64,596

 
$
119,611
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure [Table Text Block]
The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:
 
 
For the Years Ended December 31,
 
 
2013
 
2012
 
2011
Production (MMcfe)
 
172,380

 
156,325

 
153,504

Average gas sales price before effects of financial settlements (per Mcf)
 
$
3.85

 
$
3.00

 
$
4.27

Average effects of financial settlements (per Mcf)
 
$
0.45

 
$
1.22

 
$
0.63

Average gas sales price including effects of financial settlements (per Mcf)
 
$
4.30

 
$
4.22

 
$
4.90

Average lifting costs, excluding ad valorem and severance taxes (per Mcf)
 
$
0.56

 
$
0.58

 
$
0.68
Schedule of Gas and Oil Acreage [Table Text Block]
Most of our development wells and proved acreage are located in Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2013, the number of producing wells, developed acreage and undeveloped acreage:
 
 
Gross
 
Net(1)
Producing Wells (including gob wells)
 
15,063

 
12,874

Proved Developed Acreage
 
542,388

 
527,693

Proved Undeveloped Acreage
 
105,019

 
59,346

Unproved Acreage
 
5,396,659

 
4,212,030

     Total Acreage
 
6,044,066

 
4,799,069

____________
(1)
Net acres include acreage attributable to our working interests of the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
The gas reserves estimates are as follows:
 
 
 
 
 
 
Condensate
 
Consolidated
 
 
Natural Gas
 
NGLs
 
& Crude Oil
 
Operations
 
 
(MMcfe)
 
(Mbbls)
 
(Mbbls)
 
(MMcfe)
Balance December 31, 2010
 
3,724,361

 
—

 
1,206

 
3,731,597

Revisions (a)
 
(76,486
)
 
25

 
416

 
(73,837
)
Price Changes
 
(9,976
)
 
—

 
—

 
(9,976
)
Extensions and Discoveries (c)
 
517,023

 
—

 
27

 
517,178

Production
 
(152,940
)
 
—

 
(94
)
 
(153,504
)
Sales of Reserves In-Place
 
(531,431
)
 
—

 
—

 
(531,431
)
Balance December 31, 2011 (d)
 
3,470,551

 
25

 
1,555

 
3,480,027

Revisions (b)
 
243,442

 
469

 
(710
)
 
241,989

Price Changes
 
(526,608
)
 
—

 
(1
)
 
(526,611
)
Extensions and Discoveries (c)
 
873,104

 
12,992

 
553

 
954,378

Production
 
(155,052
)
 
(111
)
 
(100
)
 
(156,325
)
Sales of Reserves In-Place
 
—

 
—

 
—

 
—

Balance December 31, 2012 (d)
 
3,905,437

 
13,375

 
1,297

 
3,993,458

Revisions (b)
 
176,045

 
(1,017
)
 
336

 
171,953

Price Changes
 
104,728

 
4

 
1

 
104,757

Extensions and Discoveries (c)
 
1,567,634

 
9,623

 
1,343

 
1,633,426

Production
 
(168,737
)
 
(438
)
 
(170
)
 
(172,380
)
Sales of Reserves In-Place
 
—

 
—

 
—

 
—

Balance December 31, 2013 (d)
 
5,585,107

 
21,547

 
2,807

 
5,731,214

 
 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
 
 
 
December 31, 2011
 
2,126,330

 
—

 
1,579

 
2,135,805

December 31, 2012
 
2,149,912

 
1,717

 
878

 
2,165,483

December 31, 2013
 
2,470,412

 
5,939

 
1,375

 
2,514,294

 
 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 
 
 
 
 
 
 
 
December 31, 2011
 
1,344,222

 
—

 
—

 
1,344,222

December 31, 2012
 
1,755,525

 
12,075

 
—

 
1,827,975

December 31, 2013
 
3,114,695

 
15,607

 
1,431

 
3,216,920

__________
(a)
Revisions are primarily due corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes were partially offset by upward revisions attributable to efficiencies in operations and well performance and had the total affect of a negative revision for 2011.
(b)
Revisions are primarily due to corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance and had the total affect of the positive revisions for 2013 and 2012.
(c)
Extensions and Discoveries are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.
(d)
Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operat
Schedule of Aging of Capitalized Exploratory Well Costs [Table Text Block]
The following table represents the capitalized exploratory well cost activity as indicated:
 
 
December 31,
 
 
2013
Costs pending the determination of proved reserves at December 31, 2013
 
 
For a period one year or less
 
$
17,728

For a period greater than one year but less than five years
 
—

For a period greater than five years
 
—

     Total
 
$
17,728
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]
 
 
December 31,
 
 
2013
 
2012
 
2011
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves
 
$
12,140

 
$
14,447

 
$
189

Costs expensed due to determination of dry hole or abandonment of project
 
$
8,596

 
$
3,320

 
$
5,108