SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Unuadited) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Rate		Dec. 31, 2012 Rate		Dec. 31, 2011 Rate
Principal Sources of Change:
Sales of natural gas, NGL and crude oil production, net of production costs	$ (286,021,000)		$ (194,346,000)		$ (226,227,000)
Net changes in prices and production costs	89,527,000	[1]	95,501,000	[1]	383,293,000	[1]
Extensions, discoveries and improved recovery, less related costs	1,529,006,000	[2]	632,781,000	[2]	467,347,000	[2]
Sales of reserves	(142,724,000)	[3]	(86,902,000)	[3]	(4,224,000)	[3]
Purchases of reserves	10,610,000	[4]	296,208,000	[4]	64,761,000	[4]
Development costs incurred during the period	46,366,000		69,198,000		94,941,000
Revisions of previous quantity estimates	(397,738,000)	[5]	(452,775,000)	[5]	(112,468,000)	[5]
Changes in estimated income taxes	(381,369,000)	[6]	(131,256,000)	[6]	(204,377,000)	[6]
Net change in future development costs	(40,707,000)		(3,979,000)		(29,827,000)
Accretion of discount	142,040,000		124,105,000		65,284,000
Timing and other	44,676,000		(121,247,000)		(45,712,000)
Total	613,666,000		227,288,000		452,791,000
Notes to Changes in SMOG [Abstract]
Weighted-Average price, net of production cost	$ 24.24		$ 20.70		$ 19.14
Percentage Change in Extensions and Discoveries	142.00%		35.00%
Increase in Extensions and Discoveries			30.00%
Gas component of extensions and discoveries			52.20%
Liquids component of extensions and discoveries			47.80%
Increase in extensions and discoveries related to PUDs			86.00%
Long-Term Deferred Tax Rate	38.00%		38.20%		38.10%

[1] Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $24.24 as compared to $20.70 in our 2012 reserve report. This is due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which further increased our liquids as a percentage of proved reserves. Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Boe, in our 2012 reserve report increased to $20.70 from $19.14 resulting from our increase in liquids as a percentage of total proved reserves.

[2] The 142% increase in 2013 as compared to 2012 is primarily due to the additions of PUDs in the Utica Shale and our continued focus on our Wattenberg drilling program. Our increased PUD count in Wattenberg is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report. The 35% increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 68 MMBoe, a 30% increase, 52.2% of which was gas and 47.8% was liquids. Approximately 86% of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program.

[3] The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013. The increase in sales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012.

[4] The decrease in purchases of reserves in 2013 as compared to 2012 was due to no material acquisitions having occurred in 2013. The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field.

[5] The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule. The change in revisions of our previous quantity estimates in 2012 as compared to 2011 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments due to our drilling schedule.

[6] The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38.0%, 38.2% and 38.1% for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital.