SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Supplemental Information on Natural Gas and Crude Oil Exploration, Development and Production Activities (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities [Abstract]

Schedule of Prices Used to Estimate Natural Gas and Crude Oil Reserves [Table Text Block]

The price used to estimate our reserves, by commodity, are presented below.

	Price Used to Estimate Reserves
As of December 31,	Natural Gas (per Mcf)		NGLs (per Bbl)		Crude Oil (per Bbl)
2012	$	2.35	$	28.02	$	87.51
2011	3.41		39.59		88.94
2010	3.54		34.12		71.95

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

The following tables present the changes in our estimated quantities of proved reserves:

	Natural Gas (MMcf)		NGLs (MBbls)		Crude Oil, Condensate (MBbls)		Total (MMcfe)
Proved Reserves:
Proved reserves, January 1, 2010	608,925		—		18,070		717,345
Revisions of previous estimates	6,504		8,908		(85	)	59,442
Extensions, discoveries and other additions
Western Operating Region	56,524		811		2,247		74,872
Eastern Operating Region	35,092		—		—		35,092
Purchases of reserves
Western Operating Region	20,920		1,531		4,367		56,308
Eastern Operating Region	220		—		—		220
Other	—		—		—		—
Dispositions	(43,690	)	—		(55	)	(44,020	)
Production	(27,189	)	(601	)	(1,308	)	(38,643	)
Proved reserves, December 31, 2010	657,306		10,649		23,236		860,616
Revisions of previous estimates	(161,654	)	3,163		(1,904	)	(154,100	)
Extensions, discoveries and other additions
Western Operating Region	125,374		5,633		17,092		261,724
Eastern Operating Region	51,315		—		—		51,315
Purchases of reserves
Western Operating Region	24,776		1,052		1,581		40,574
Eastern Operating Region	7,985		—		24		8,129
Dispositions	(2,070	)	(94	)	(435	)	(5,244	)
Production	(30,887	)	(815	)	(1,958	)	(47,525	)
Proved reserves, December 31, 2011 (1)	672,145		19,588		37,636		1,015,489
Revisions of previous estimates	(289,436	)	(3,671	)	(6,729	)	(351,836	)
Extensions, discoveries and other additions
Western Operating Region	116,205		11,637		27,482		350,919
Eastern Operating Region	56,728		—		—		56,728
Purchases of reserves
Western Operating Region	87,189		8,084		10,801		200,499
Eastern Operating Region	23		—		—		23
Dispositions	(6,406	)	(1,970	)	(7,854	)	(65,350	)
Production	(32,410	)	(841	)	(2,026	)	(49,612	)
Proved reserves, December 31, 2012 (2)	604,038		32,827		59,310		1,156,860

Proved Developed Reserves, as of:
January 1, 2010	258,375	—	6,244	295,839
December 31, 2010	227,341	4,013	8,287	301,141
December 31, 2011 (1)	299,369	11,753	16,910	471,347
December 31, 2012 (2)	281,925	14,353	20,412	490,515
Proved Undeveloped Reserves, as of:
January 1, 2010	350,550	—	11,826	421,506
December 31, 2010	429,965	6,636	14,949	559,475
December 31, 2011 (1)	372,776	7,835	20,726	544,142
December 31, 2012 (2)	322,113	18,474	38,898	666,345

__________

(1) Includes estimated reserve data related to our Permian asset group, which was held for sale and under a purchase and sale agreement. The divestiture of our Permian assets closed on February 28, 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included in this Exhibit 99.1 for additional details related to the divestiture of our Permian asset group. Total proved reserves included 6,242 MMcf of natural gas, 7,825 MBbls of crude oil and 1,970 MBbls of NGLs, for an aggregate of 65,018 MMcfe of natural gas equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,750 MMcf, 1,815 MBbls, 550 MBbls and 15,940 MMcfe, respectively, and proved undeveloped reserves included 4,492 MMcf, 6,010 MBbls, 1,420 MBbls and 49,078 MMcfe, respectively.

(2) Includes estimated reserve data related to our Piceance and NECO assets, which were divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations, to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 83,656 MMcf of natural gas and 148 MBbls of crude oil, for an aggregate of 84,544 MMcfe of natural gas equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012.

	Developed		Undeveloped		Total
	(MMcfe)
Beginning proved reserves, January 1, 2011	301,141		559,475		860,616
Undeveloped reserves converted to developed	43,597		(43,597	)	—
Revisions of previous estimates	73,643		(227,743	)	(154,100	)
Extensions, discoveries and other additions	58,979		254,060		313,039
Purchases of reserves	46,756		1,947		48,703
Dispositions	(5,244	)	—		(5,244	)
Production	(47,525	)	—		(47,525	)
Ending proved reserves, December 31, 2011	471,347		544,142		1,015,489
Undeveloped reserves converted to developed	45,929		(45,929	)	—
Revisions of previous estimates	(109,909	)	(241,927	)	(351,836	)
Extensions, discoveries and other additions	67,787		339,860		407,647
Purchases of reserves	81,253		119,269		200,522
Dispositions	(16,280	)	(49,070	)	(65,350	)
Production	(49,612	)	—		(49,612	)
Ending proved reserves, December 31, 2012	490,515		666,345		1,156,860

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

The results of operations for natural gas and crude oil producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services.

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Revenue:
Natural gas, NGLs and crude oil sales	$	274,783		$	304,157		$	216,159
Commodity price risk management gain, net	32,339			46,090			59,891
	307,122			350,247			276,050
Expenses:
Production costs	77,537			75,717			60,121
Exploration expense	22,605			6,289			20,291
Impairment of proved natural gas and oil properties	162,287			25,159			4,666
Depreciation, depletion, and amortization	146,879			128,458			103,303
Accretion of asset retirement obligations	4,060			1,897			1,423
Gain on sale of properties and equipment	(24,273		)	(4,050		)	(174		)
	389,095			233,470			189,630
Results of operations for natural gas and crude oil producing activities before provision for income taxes	(81,973		)	116,777			86,420
Provision for income taxes	31,163			(36,785		)	(5,937		)
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs	$	(50,810	)	$	79,992		$	80,483

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

Costs incurred in natural gas and crude oil property acquisition, exploration and development are presented below.

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Acquisition of properties: (1)
Proved properties	$	105,303	$	79,554	$	87,241
Unproved properties	276,225		95,081		84,636
Development costs (2)	233,144		301,008		138,018
Exploration costs: (3)
Exploratory drilling	18,803		3,626		21,223
Geological and geophysical	1,925		1,846		2,367
Total costs incurred	$	635,400	$	481,115	$	333,485

__________

(1) Property acquisition costs - represent costs incurred to purchase, lease or otherwise acquire a property.

(2) Development costs - represents costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store natural gas, NGLs and crude oil. Of these costs incurred for the years ended December 31, 2012, 2011 and 2010, $62.0 million, $80.6 million and $37.4 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.

(3) Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing natural gas, NGLs and crude oil.

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Aggregate capitalized costs related to natural gas and crude oil exploration and production activities with applicable accumulated DD&A are presented below:

	As of December 31,
	2012			2011
	(in thousands)
Proved natural gas and crude oil properties	$	2,075,924		$	1,694,847
Unproved natural gas and crude oil properties	319,327			102,466
Capitalized costs	2,395,251			1,797,313
Less accumulated DD&A	(905,458		)	(621,074		)
Capitalized costs, net	$	1,489,793		$	1,176,239

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for natural gas, NGLs and crude oil, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.

	As of December 31,
	2012			2011			2010
	(in thousands)
Future estimated cash flows	$	7,529,292		$	6,415,255		$	4,361,095
Future estimated production costs	(1,690,453		)	(1,704,645		)	(1,418,044		)
Future estimated development costs	(1,852,177		)	(1,474,137		)	(1,119,604		)
Future estimated income tax expense	(1,230,294		)	(946,849		)	(508,805		)
Future net cash flows	2,756,368			2,289,624			1,314,642
10% annual discount for estimated timing of cash flows	(1,587,871		)	(1,348,415		)	(826,224		)
Standardized measure of discounted future estimated net cash flows	$	1,168,497		$	941,209		$	488,418

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Sales of natural gas, NGLs and crude oil production, net of production costs	$	(194,346	)	$	(226,227	)	$	(163,104	)
Net changes in prices and production costs (1)	95,501			383,293			180,124
Extensions, discoveries, and improved recovery, less related costs (2)	632,781			467,347			88,637
Sales of reserves (3)	(86,902		)	(4,224		)	(24,174		)
Purchases of reserves (4)	296,208			64,761			45,538
Development costs incurred during the period	69,198			94,941			44,491
Revisions of previous quantity estimates (5)	(452,775		)	(112,468		)	47,884
Changes in estimated income taxes (6)	(131,256		)	(204,377		)	(105,557		)
Net changes in future development costs	(3,979		)	(29,827		)	(41,595		)
Accretion of discount	124,105			65,284			35,951
Timing and other	(121,247		)	(45,712		)	32,587
Total	$	227,288		$	452,791		$	140,782

__________

(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) 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 increase in purchases 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.