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Supplemental Gas Data (Tables)
 12 Months Ended
Dec. 31, 2014
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,
 
 
2014
 
2013
 
2012
Future Cash Flows:
 
 
 
 
 
 
Revenues
 
$
28,502,852

 
$
21,602,594

 
$
11,777,550

Production costs
 
(10,100,868
)
 
(7,105,962
)
 
(4,823,670
)
Development costs
 
(3,368,621
)
 
(3,902,875
)
 
(2,450,589
)
Income tax expense
 
(5,711,989
)
 
(4,025,626
)
 
(1,711,251
)
Future Net Cash Flows
 
9,321,374

 
6,568,131

 
2,792,040

Discounted to present value at a 10% annual rate
 
(6,337,216
)
 
(4,887,320
)
 
(2,055,834
)
Total standardized measure of discounted net cash flows
 
$
2,984,158

 
$
1,680,811

 
$
736,206

The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
 
 
December 31,
 
 
2014
 
2013
 
2012
Balance at beginning of period
 
$
1,680,811

 
$
736,206

 
$
1,747,181

Net changes in sales prices and production costs
 
517,731

 
1,295,956

 
(1,480,573
)
Sales net of production costs
 
(559,563
)
 
(365,477
)
 
(104,518
)
Net change due to revisions in quantity estimates
 
151,233

 
132,900

 
(104,158
)
Net change due to extensions, discoveries and improved recovery
 
418,775

 
383,308

 
14,645

Development costs incurred during the period
 
952,733

 
625,824

 
333,640

Difference in previously estimated development costs compared to actual costs incurred during the period
 
(102,949
)
 
(123,976
)
 
(96,749
)
Changes in estimated future development costs
 
595,221

 
(486,518
)
 
(153,104
)
Net change in future income taxes
 
(798,470
)
 
(578,951
)
 
619,045

Accretion of discount and other
 
128,636

 
61,539

 
(39,203
)
     Total discounted cash flow at end of period
 
$
2,984,158

 
$
1,680,811

 
$
736,206
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
Capitalized Costs:
 
 
As of December 31,
 
 
2014
 
2013
Proven properties
 
$
1,768,007

 
$
1,670,404

Unproven properties
 
1,540,835

 
1,463,406

Intangible drilling costs
 
2,798,394

 
1,937,336

Wells and related equipment
 
716,748

 
688,548

Gathering assets
 
1,088,238

 
1,058,008

Gas well plugging
 
111,227

 
113,481

Total Property, Plant and Equipment
 
8,023,449

 
6,931,183

Accumulated Depreciation, Depletion and Amortization
 
(1,515,983
)
 
(1,187,409
)
Net Capitalized Costs
 
$
6,507,466

 
$
5,743,774
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,
 
 
2014
 
2013
 
2012
Property acquisitions
 
 
 
 
 
 
Proven properties
 
$
—

 
$
—

 
$
50,005

Unproven properties
 
119,597

 
260,477

 
28,634

Development
 
952,733

 
629,100

 
339,608

Exploration
 
45,006

 
95,413

 
130,312

Total
 
$
1,117,336

 
$
984,990

 
$
548,559

__________
(*)
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,
 
 
2014
 
2013
 
2012
Production Revenue
 
$
1,030,574

 
$
740,869

 
$
660,442

Royalty Interest Gas Revenue
 
82,428

 
63,202

 
49,405

Purchased Gas Revenue
 
8,999

 
6,531

 
3,316

Total Revenue
 
1,122,001

 
810,602

 
713,163

Lifting Costs
 
118,391

 
96,601

 
90,837

Ad Valorem, Severance & Other Taxes
 
39,418

 
28,676

 
26,145

Gathering Costs
 
258,110

 
201,024

 
160,579

Royalty Interest Gas Costs
 
69,946

 
53,069

 
38,922

Direct Administrative, Selling & Other Costs
 
55,092

 
49,092

 
47,565

Other Costs
 
22,719

 
61,107

 
39,029

Purchased Gas Costs
 
7,251

 
4,837

 
2,711

DD&A
 
314,381

 
231,809

 
205,149

Total Costs
 
885,308

 
726,215

 
610,937

Pre-tax Operating Income
 
236,693

 
84,387

 
102,226

Income Taxes
 
82,894

 
32,067

 
38,989

Results of Operations for Producing Activities excluding Corporate and Interest Costs
 
$
153,799

 
$
52,320

 
$
63,237
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,
 
 
2014
 
2013
 
2012
Production (MMcfe)
 
235,714

 
172,380

 
156,325

Average gas sales price before effects of financial settlements (per Mcf)
 
$
4.26

 
$
3.85

 
$
3.00

Average effects of financial settlements (per Mcf)
 
$
0.11

 
$
0.45

 
$
1.22

Average gas sales price including effects of financial settlements (per Mcf)
 
$
4.37

 
$
4.30

 
$
4.22

Average lifting costs, excluding ad valorem and severance taxes (per Mcf)
 
$
0.50

 
$
0.56

 
$
0.58
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, 2014, the number of producing wells, developed acreage and undeveloped acreage:
 
 
Gross
 
Net(1)
Producing Gas Wells (including gob wells)
 
17,044

 
12,918

Producing Oil Wells
 
154

 
34

Proved Developed Acreage
 
537,935

 
515,439

Proved Undeveloped Acreage
 
112,617

 
63,801

Unproved Acreage
 
4,946,174

 
3,933,975

     Total Acreage
 
5,596,726

 
4,513,215

____________
(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, 2011 (c)
 
3,470,551

 
25

 
1,555

 
3,480,027

Revisions (a)
 
243,442

 
469

 
(710
)
 
241,989

Price Changes
 
(526,608
)
 
—

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

 
12,992

 
553

 
954,378

Production
 
(155,052
)
 
(111
)
 
(100
)
 
(156,325
)
Balance December 31, 2012 (c)
 
3,905,437

 
13,375

 
1,297

 
3,993,458

Revisions (a)
 
176,045

 
(1,017
)
 
336

 
171,953

Price Changes
 
104,728

 
4

 
1

 
104,757

Extensions and Discoveries (b)
 
1,567,634

 
9,623

 
1,343

 
1,633,426

Production
 
(168,737
)
 
(438
)
 
(170
)
 
(172,380
)
Balance December 31, 2013 (c)
 
5,585,107

 
21,547

 
2,807

 
5,731,214

Revisions (d)
 
(46,560
)
 
40,363

 
3,756

 
218,168

Price Changes
 
15,512

 
—

 
—

 
15,512

Extensions and Discoveries (e)
 
979,801

 
18,459

 
1,314

 
1,098,436

Production
 
(216,260
)
 
(2,578
)
 
(664
)
 
(235,714
)
Balance December 31, 2014 (c)
 
6,317,600

 
77,791

 
7,213

 
6,827,616

 
 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
 
 
 
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

December 31, 2014
 
2,979,906

 
32,406

 
4,062

 
3,198,706

 
 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 
 
 
 
 
 
 
 
December 31, 2012
 
1,755,525

 
12,075

 
—

 
1,827,975

December 31, 2013
 
3,114,695

 
15,607

 
1,431

 
3,216,920

December 31, 2014
 
3,337,694

 
45,385

 
3,151

 
3,628,910

__________
(a)
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 had the total affect of the positive revisions for 2013 and 2012.
(b)
Extensions and Discoveries in 2013 and 2012 are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.
(c)
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,
 
 
2014
Costs pending the determination of proved reserves at December 31, 2014
 
 
For a period one year or less
 
$
22,851

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

For a period greater than five years
 
—

     Total
 
$
22,851
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]
 
 
December 31,
 
 
2014
 
2013
 
2012
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves
 
$
27,453

 
$
12,140

 
$
14,447

Costs expensed due to determination of dry hole or abandonment of project
 
$
2,041

 
$
8,596

 
$
3,320