Supplemental Gas Data

12 Months Ended

Dec. 31, 2011

SUPPLEMENTAL GAS DATA: [Abstract]

Proved Oil and Gas Reserve Quantities Disclosure [Text Block]

Standardized Measure of Discounted Future Net Cash Flows:

The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year ended December 31, 2011. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CONSOL Energy. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CONSOL Energy's investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a different price and cost assumptions.

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,
	2011			2010			2009
Future Cash Flows:
Revenues	$	14,804,398		$	16,723,795		$	7,975,195
Production costs	(5,262,635		)	(5,175,563		)	(3,123,532		)
Development costs	(1,674,829		)	(2,720,243		)	(995,569		)
Income tax expense	(2,989,435		)	(3,354,444		)	(1,465,075		)
Future Net Cash Flows	4,877,499			5,473,545			2,391,019
Discounted to present value at a 10% annual rate	(3,130,318		)	(3,812,724		)	(1,496,668		)
Total standardized measure of discounted net cash flows	$	1,747,181		$	1,660,821		$	894,351

The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:

	December 31,
	2011			2010			2009
Balance at beginning of period	$	1,660,821		$	894,351		$	1,218,434
Net changes in sales prices and production costs	(339,098		)	721,997			(457,138		)
Sales net of production costs	(217,186		)	(286,883		)	(335,706		)
Net change due to revisions in quantity estimates	(83,580		)	414,704			189,583
Net change due to extensions, discoveries and improved recovery	324,755			326,584			124,008
Net change due to (divestiture) acquisition	(559,132		)	500,376			—
Development costs incurred during the period	463,401			295,142			181,944
Difference in previously estimated development costs compared to actual costs incurred during the period	154,137			(12,060		)	(3,282		)
Changes in estimated future development costs	155,619			(426,870		)	(380,639		)
Net change in future income taxes	130,746			(612,114		)	248,639
Accretion of discount and other	56,698			(154,406		)	108,508
Total discounted cash flow at end of period	$	1,747,181		$	1,660,821		$	894,351

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

Supplemental Gas Data (unaudited):

The following information was prepared in accordance with the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).”

Capitalized Costs:

	As of December 31,
	2011			2010
Proven properties	$	1,495,772		$	1,615,540
Unproven properties	1,258,455			2,206,827
Wells and related equipment	1,755,617			1,558,300
Gathering assets	963,494			941,772
Total Property, Plant and Equipment	5,473,338			6,322,439
Accumulated Depreciation, Depletion and Amortization	(773,027		)	(623,575		)
Net Capitalized Costs	$	4,700,311		$	5,698,864

Costs incurred for property acquisition, exploration and development (*):

	For the Years Ended December 31,
	2011		2010		2009
Property acquisitions
Proven properties	$	6,673	$	1,476,470	$	30,405
Unproven properties	58,731		1,922,334		50,705
Development	463,401		472,691		181,944
Exploration	131,419		58,655		46,023
Total	$	660,224	$	3,930,150	$	309,077

__________

(*) Includes costs incurred whether capitalized or expensed.

Results of Operations for Producing Activities:

	For the Years Ended December 31,
	2011		2010		2009
Production Revenue	$	751,767	$	745,809	$	630,598
Royalty Interest Gas Revenue	66,929		62,869		40,951
Purchased Gas Revenue	4,344		11,227		7,040
Total Revenue	823,040		819,905		678,589
Lifting Costs	131,184		87,155		55,285
Gathering Costs	142,339		127,927		95,687
Royalty Interest Gas Costs	59,377		53,839		32,423
Other Costs	62,302		63,941		45,795
Purchased Gas Costs	3,831		9,736		6,442
DD&A	206,821		190,424		107,251
Total Costs	605,854		533,022		342,883
Pre-tax Operating Income	217,186		286,883		335,706
Income Taxes	86,961		117,278		125,890
Results of Operations for Producing Activities excluding Corporate and Interest Costs	$	130,225	$	169,605	$	209,816

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,
	2011		2010		2009
Production in million cubic feet	153,504		127,875		94,415
Average gas sales price before effects of financial settlements (per thousand cubic feet)	$	4.27	$	4.53	$	4.15
Average effects of financial settlements (per thousand cubic feet)	$	0.63	$	1.30	$	2.53
Average gas sales price including effects of financial settlements (per thousand cubic feet)	$	4.90	$	5.83	$	6.68
Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.68	$	0.50	$	0.48

During the years ended December 31, 2011, 2010 and 2009, we drilled 254.9, 317 and 247 net development wells, respectively. There were no net dry development wells in 2011, one net dry development well in 2010 and one net dry development well in 2009.

During the years ended December 31, 2011, 2010 and 2009, we drilled 69.5, 38 and 18 net exploratory wells, respectively. There were two net dry exploratory wells in 2011, two net dry exploratory wells in 2010 and one net dry exploratory well in 2009.

At December 31, 2011, there were 47 net development wells in the process of being drilled.

At December 31, 2011, there were 2.5 net exploratory wells in the process of being drilled.

CONSOL Energy is committed to provide 89.8 bcf of gas under existing sales contracts or agreements over the course of the next four years. CONSOL Energy expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.

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, 2011, the number of producing wells, developed acreage and undeveloped acreage:

	Gross	Net(1)
Producing Wells (including gob wells)	14,743	12,725
Proved Developed Acreage	507,949	421,874
Proved Undeveloped Acreage	146,479	124,276
Unproved Acreage	5,035,749	4,040,598
Total Acreage	5,690,177	4,586,748

____________

(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.

Proved Oil and Gas Reserve Quantities:

The preparation of our gas reserve estimates are completed in accordance with CONSOL Energy's prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer. Our 2011 gas reserve results were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer. The gas reserve estimates are as follows:

	Consolidated Operations
	2011		2010		2009
Net Reserve Quantity (MMcfe)
Beginning reserves	3,731,597		1,911,391		1,422,046
Revisions(a)	(83,813	)	379,977		177,004
Extensions and discoveries(b)	517,178		621,270		406,756
Production	(153,504	)	(127,875	)	(94,415	)
Purchases of reserves in-place	—		946,834		—
Sale of reserves in-place	(531,431	)	—		—
Ending reserves(c)	3,480,027		3,731,597		1,911,391

__________

(a) Revisions are due to price, efficiencies in operations, and changes in the current five year plan as well as a comprehensive look into reservoir characterization and well performance.

(b) Extensions and Discoveries are due to the drilling of proved undeveloped, probable and possible locations adhering to Security and Exchange Commission (SEC) guidelines on booking PUD locations if reliable technology can be demonstrated. The reliable technologies that were utilized include wire line open-hole log data, performance data, log cross sections, core data, and statistical analysis.  The statistical method utilized production performance from CONSOL Energy's and competitors' wells.  Geophysical data includes data from CONSOL Energy's wells, published documents, and state data-sites and was used to confirm continuity of the formation.

(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 operating conditions and government regulations. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.

	2011			2010			2009
	All	Natural	Oil	All	Natural	Oil	All	Natural	Oil
	Products	Gas mmcf	mmcfe (a)	Products	Gas mmcf	mmcfe (a)	Products	Gas mmcf	mmcfe (a)
Proved developed reserves (consolidated entities only)
Beginning of year	1,931,272	1,924,036	7,236	1,040,257	1,039,052	1,205	783,290	783,010	280
End of year	2,135,805	2,126,330	9,475	1,931,272	1,924,036	7,236	1,040,257	1,039,052	1,205
Proved undeveloped reserves (consolidated entities only)
Beginning of year	1,800,325	1,800,325	—	871,134	871,134	—	638,756	638,756	—
End of year	1,344,222	1,344,222	—	1,800,325	1,800,325	—	871,134	871,134	—

_________

(a) Gas equivalent reserves are expressed in billions of cubic feet equivalent (BCFE), determined using the ratio of 6 billion cubic feet of gas to 1 million barrels of oil.

	For the Year
	Ended
	December 31,
	2011
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves	1,800,325
Undeveloped reserves transferred to developed(a)	(200,849	)
Disposition of reserves in place	(278,581	)
Revisions	(362,770	)
Extension and discoveries	386,097
Ending proved undeveloped reserves(b)	1,344,222

_________

(a) During 2011, various exploration and development drilling and evaluations were completed. Approximately, $134,064 of capital was spent in the year ended December 31, 2011 related to undeveloped reserves that were transferred to developed.

(b) Included in proved undeveloped reserves at December 31, 2011 are approximately 121,003 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports the continual operation of the mine for many years past, unless there was an extreme circumstance which resulted from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.

The following table represents the capitalized exploratory well cost activity as indicated:

	December 31,
	2011
Costs pending the determination of proved reserves at December 31, 2011(a)
Less than one year	$	—
More than one year but less than five years	3,309
More than five years	2,171
Total	$	5,480

__________

(a) Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned exploration expenditures will allow us to invest in infrastructure to support these fields. During 2011, three wells were removed from the previous year-end schedule. One of these wells was connected and is now producing while two wells were determined to be dry or uneconomical to pursue and expensed.

	December 31,
	2011		2010		2009
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves	$	189	$	93,482	$	52,332
Costs expensed due to determination of dry hole or abandonment of project	$	5,108	$	9,614	$	8,194

CONSOL Energy's proved gas reserves are located in the United States.