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, 2015

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]

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

	Price Used to Estimate Reserves*
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2015	$	42.10	$	2.05	$	12.23
2014	84.65		3.92		32.27
2013	82.18		3.22		29.92

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:

	Crude Oil, Condensate (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Proved Reserves:
Proved reserves, January 1, 2013 (1)	59,310		604,038		32,827		192,810
Revisions of previous estimates	(18,420	)	(117,068	)	(8,549	)	(46,480	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	55,759		365,563		25,249		141,935
Purchases of reserves	343		2,894		217		1,043
Dispositions	(252	)	(94,927	)	(30	)	(16,104	)
Production	(2,910	)	(20,860	)	(1,043	)	(7,430	)
Proved reserves, December 31, 2013 (2)	93,830		739,640		48,671		265,774
Revisions of previous estimates	(29,777	)	(149,064	)	(10,204	)	(64,825	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	40,792		202,957		23,411		98,029
Purchases of reserves	5		43		5		17
Dispositions	(13	)	(237,306	)	(8	)	(39,572	)
Production	(4,322	)	(19,298	)	(1,756	)	(9,294	)
Proved reserves, December 31, 2014	100,515		536,972		60,119		250,129
Revisions of previous estimates	(43,268	)	(154,775	)	(24,407	)	(93,471	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	48,707		311,709		30,835		131,494
Purchases of reserves	17		215		23		76
Dispositions	(12	)	(82	)	(8	)	(34	)
Production	(6,984	)	(33,302	)	(2,835	)	(15,369	)
Proved reserves, December 31, 2015	98,975		660,737		63,727		272,825

Proved Developed Reserves, as of:
January 1, 2013 (1)	20,412	281,925	14,353	81,753
December 31, 2013 (2)	23,997	220,387	14,825	75,553
December 31, 2014	26,798	186,633	17,002	74,905
December 31, 2015	26,257	175,367	15,011	70,496
Proved Undeveloped Reserves, as of:
January 1, 2013 (1)	38,898	322,113	18,474	111,058
December 31, 2013 (2)	69,833	519,253	33,846	190,221
December 31, 2014	73,717	350,339	43,117	175,224
December 31, 2015	72,718	485,370	48,716	202,329

__________

(1) Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil 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.

(2) Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Marcellus Shale assets. Total proved reserves included 235,950 MMcf of natural gas, for an aggregate of 39,325 Mboe of crude oil equivalent, related to our Marcellus Shale assets. Total proved developed reserves related to those assets included 53,904 MMcf and 8,984 MBoe, respectively, and proved undeveloped reserves included 182,046 MMcf and 30,341 MBoe, respectively.

	Developed		Undeveloped		Total
	(MBoe)
Beginning proved reserves, January 1, 2013	81,753		111,057		192,810
Production	(7,430	)	—		(7,430	)
Undeveloped reserves converted to developed	3,212		(3,212	)	—
Purchases of reserves	1,043		—		1,043
Dispositions	(16,104	)	—		(16,104	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	19,830		122,105		141,935
Revisions of previous estimates	(6,751	)	(39,729	)	(46,480	)
Ending proved reserves, December 31, 2013	75,553		190,221		265,774
Production	(9,294	)	—		(9,294	)
Undeveloped reserves converted to developed	12,730		(12,730	)	—
Purchases of reserves	17		—		17
Dispositions	(9,231	)	(30,341	)	(39,572	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	27,957		70,072		98,029
Revisions of previous estimates	(22,827	)	(41,998	)	(64,825	)
Ending proved reserves, December 31, 2014	74,905		175,224		250,129
Production	(15,369	)	—		(15,369	)
Undeveloped reserves converted to developed	29,090		(29,090	)	—
Purchases of reserves	76		—		76
Dispositions	(34	)	—		(34	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	8,703		122,791		131,494
Revisions of previous estimates	(26,875	)	(66,596	)	(93,471	)
Ending proved reserves, December 31, 2015	70,496		202,329		272,825

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

The results of operations for crude oil and natural gas 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,
	2015			2014			2013
	(in thousands)
Revenue:
Crude oil, natural gas and NGLs sales	$	378,713		$	495,562		$	379,796
Commodity price risk management gain (loss), net	203,183			309,219			(23,905		)
	581,896			804,781			355,891
Expenses:
Lease operating expenses	56,992			43,682			40,339
Production taxes	18,443			27,194			25,474
Transportation, gathering and processing expenses	10,151			8,128			10,435
Exploration expense	1,102			948			7,071
Impairment of proved crude oil and natural gas properties	161,620			167,280			53,827
Depreciation, depletion, and amortization	298,760			201,656			124,202
Accretion of asset retirement obligations	6,293			3,455			4,747
(Gain) loss on sale of properties and equipment	(385		)	(75,972		)	3,722
	552,976			376,371			269,817
Results of operations for crude oil and natural gas producing activities before provision for income taxes	28,920			428,410			86,074
Provision for income taxes	(10,394		)	(166,930		)	(31,109		)
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	18,526		$	261,480		$	54,965

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

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Acquisition of properties: (1)
Proved properties	$	3,561	$	11,973	$	28,698
Unproved properties	15		45,999		3,390
Development costs (2)	552,104		608,176		338,294
Exploration costs: (3)
Exploratory drilling	—		—		58,988
Geological and geophysical	—		1		752
Total costs incurred	$	555,680	$	666,149	$	430,122

__________

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

(2) Development costs represent 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 crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2015, 2014 and 2013, $207.8 million, $125.2 million and $40.1 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 crude oil, natural gas and NGLs.

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

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

	As of December 31,
	2015			2014
	(in thousands)
Proved crude oil and natural gas properties	$	2,881,189		$	2,267,165
Unproved crude oil and natural gas properties	60,498			188,206
Uncompleted wells, equipment and facilities	109,385			164,402
Capitalized costs	3,051,072			2,619,773
Less accumulated DD&A	(1,131,705		)	(808,431		)
Capitalized costs, net	$	1,919,367		$	1,811,342

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 crude oil, natural gas and NGLs, 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,
	2015			2014			2013
	(in thousands)
Future estimated cash flows	$	6,297,298		$	12,550,515		$	11,550,917
Future estimated production costs*	(1,577,393		)	(2,816,776		)	(2,329,836		)
Future estimated development costs	(1,952,332		)	(2,458,790		)	(2,778,148		)
Future estimated income tax expense	(508,332		)	(2,336,510		)	(2,119,615		)
Future net cash flows	2,259,241			4,938,439			4,323,318
10% annual discount for estimated timing of cash flows	(1,162,377		)	(2,631,974		)	(2,541,155		)
Standardized measure of discounted future estimated net cash flows	$	1,096,864		$	2,306,465		$	1,782,163

___________

* Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses and plugging and abandonment costs, net of salvage value.

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,
	2015			2014			2013
	(in thousands)
Sales of crude oil, natural gas and NGLs production, net of production costs	$	(293,127	)	$	(387,789	)	$	(286,021	)
Net changes in prices and production costs (1)	(1,752,921		)	129,213			89,527
Extensions, discoveries, and improved recovery, including infill reserves in an existing proved field, less related costs (2)	489,178			1,444,581			1,529,006
Sales of reserves (3)	(463		)	(402,595		)	(142,724		)
Purchases of reserves (4)	374			238			10,610
Development costs incurred during the period	368,840			161,404			46,366
Revisions of previous quantity estimates (5)	(1,286,462		)	(654,318		)	(397,738		)
Changes in estimated income taxes (6)	902,994			(221,874		)	(381,369		)
Net changes in future development costs	112,958			46,499			(40,707		)
Accretion of discount	345,007			270,389			142,040
Timing and other	(95,979		)	138,554			44,676
Total	$	(1,209,601	)	$	524,302		$	613,666

__________

(1) Our weighted-average price, net of production costs per Boe, in our 2015 reserve report decreased to $17.30 as compared to $37.78 in our 2014 reserve report. This is due to the significant decrease in SEC commodity prices utilized in the 2015 reserve report. Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to $37.78 from $30.82 in our 2013 reserve report. This is due to the divestiture of our Marcellus Shale reserves during 2014 which further increased our liquids as a percentage of proved reserves.

(2) The 66% decrease in 2015 indicates a significant decrease in the value of the extensions in 2015 as compared to the value of the extensions in 2014. This is primarily due to lower SEC commodity prices utilized in the 2015 reserve report. The 6% decrease in 2014 as compared to 2013 is primarily due to a scheduled maximum rig count of six rigs by 2016 as compared to a scheduled maximum rig count of seven in the 2013 year-end reserve report, partially offset by our increased PUD count in the Wattenberg Field resulting from successful downspacing tests in 2014.

(3) The decrease in sales of reserves in 2015 was due to the fact that no major divestitures were completed in 2015. The increase in sales of reserves in 2014 as compared to 2013 was due to the divestiture of our Marcellus shale assets in October 2014.

(4) The decrease in purchases of reserves in 2015 and 2014 as compared to the respective prior years was due to no material acquisitions having occurred.

(5) The change in revisions of our previous quantity estimates in 2015 as compared to 2014 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2014 as compared to 2013 was primarily due to 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 changes in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38% for each of the three years ended December 31, 2015, 2014 and 2013. 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.