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, 2012 Rate		Dec. 31, 2011 Rate		Dec. 31, 2010 Rate
Principal Sources of Change:
Sales of natural gas, NGL and crude oil production, net of production costs	$ (194,346,000)		$ (226,227,000)		$ (163,104,000)
Net changes in prices and production costs	95,501,000	[1]	383,293,000	[1]	180,124,000	[1]
Extensions, discoveries and improved recovery, less related costs	632,781,000	[2]	467,347,000	[2]	88,637,000	[2]
Sales of reserves	(86,902,000)	[3]	(4,224,000)	[3]	(24,174,000)	[3]
Purchases of reserves	296,208,000	[4]	64,761,000	[4]	45,538,000	[4]
Development costs incurred during the period	69,198,000		94,941,000		44,491,000
Revisions of previous quantity estimates	(452,775,000)	[5]	(112,468,000)	[5]	47,884,000	[5]
Changes in estimated income taxes	(131,256,000)	[6]	(204,377,000)	[6]	(105,557,000)	[6]
Net change in future development costs	(3,979,000)		(29,827,000)		(41,595,000)
Accretion of discount	124,105,000		65,284,000		35,951,000
Timing and other	(121,247,000)		(45,712,000)		32,587,000
Total	227,288,000		452,791,000		140,782,000
Notes to Changes in SMOG [Abstract]
Weighted-Average price, net of production cost	$ 3.45		$ 3.19		$ 2.12
Percentage Change in Extensions and Discoveries	35.00%		427.00%
Gas component of extensions and discoveries	52.20%		56.40%		83.30%
Liquids component of extensions and discoveries	47.80%		43.60%		16.70%
Increase in Extensions and Discoveries	30.00%		185.00%
Increase in extensions and discoveries related to PUDs	86.00%
Horizontal Wells Drilled			17
Vertical Wells Drilled			80
Zones Completed			190
Non-Operated Drilling Projects			48
Long-Term Deferred Tax Rate	38.20%		38.10%		38.00%

[1] Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Mcfe, in our 2012 reserve report increased to $3.45 from $3.19 resulting from our increase in liquids as a percentage of total proved reserves. Our weighted-average price, net of production costs per Mcfe, in our 2010 reserve report was $2.12.

[2] 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 407,647 MMcfe, 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. The changes in extensions, discoveries and improved recovery, less related costs, were 427% higher in 2011 as compared to 2010. At December 31, 2010, extensions, discoveries and other additions were 109,964 MMcfe, 83.3% of which was gas and 16.7% of which was liquids. At December 31, 2011, extensions, discoveries and other additions had increased to 313,039 MMcfe, a 185% increase, 56.4% of which was gas and 43.6% was liquids. This change was a result of our shifting of focus from gas-rich projects to liquid-rich projects. In 2011, we focused primarily on the liquids-rich Wattenberg Field in northern Colorado, where we drilled 17 horizontal Niobrara wells and 80 vertical wells, completed 190 zones and participated in 48 non-operated drilling projects. 2011 was the first year that horizontal Niobrara PUDs were included in our year-end reserves. All of these projects are liquid-rich and, with the exception of the vertical wells and refractures, these reserves were not recognized at December 31, 2010. As a result, approximately two-thirds of the 427% increase is related to additional volumes included in our reserve report in 2011 over those included in 2010 and one-third of the increase is related to the per Mcfe value increase of those additional volume of reserves.

[3] ales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012.

[4] urchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field in northern Colorado.

[5] The decrease 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. The decrease in 2011 as compared to 2010 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments for geological reasons, offset in part by improvements in asset performance.

[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 38.2%, 38.1% and 38% for the year ended December 31, 2012, 2011 and 2010, 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.