PDC Energy (PDCE) 10-K 22 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document Document - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 01, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	PDC ENERGY, INC.
Entity Central Index Key	77,877
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,269,891
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,121,413,563

Consolidated Balance Sheets (Au

Consolidated Balance Sheets (Audited) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 850	$ 16,066
Accounts receivable, net	104,274	131,204
Derivative Instruments and Hedges, Assets	221,659	187,495
Prepaid expenses and other current assets	5,266	5,954
Total current assets	332,049	340,719
Properties and equipment, net	1,937,678	1,827,454
Assets Held-for-sale	2,874	2,874
Fair value of derivatives	44,387	112,819
Other assets	53,555	47,274
Total Assets	2,370,543	2,331,140
Current liabilities:
Accounts payable	92,613	130,321
Production tax liability	26,524	21,314
Fair value of derivatives	1,595	570
Funds held for distribution	29,894	27,186
Current portion of long-term debt	112,940	0
Accrued interest payable	9,057	9,109
Other accrued expenses	28,709	62,717
Total current liabilities	301,332	251,217
Long-term debt	529,437	655,475
Deferred income taxes	143,452	184,867
Asset retirement obligations	84,032	71,992
Fair value of derivatives	695	197
Other liabilities	24,398	30,033
Total liabilities	1,083,346	1,193,781
Shareholders' Equity:
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized,none issued	0	0
Common shares - par value $0.01 per share, 150,000,000 authorized, 40,174,776 and 35,927,985 issued as of December 31, 2015 and 2014, respectively	402	359
Additional paid-in capital	907,382	689,209
Retained earnings	380,422	448,702
Treasury shares - at cost, 20,220 and 21,643 as of December 31, 2015 and 2014, respectively	(1,009)	(911)
Total shareholders' equity	1,287,197	1,137,359
Total Liabilities and Shareholders' Equity	$ 2,370,543	$ 2,331,140

Balance Sheet Parentheticals (P

Balance Sheet Parentheticals (Parentheticals) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Balance Sheet Parentheticals [Abstract]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	150,000,000	150,000,000
Common Stock, Shares, Issued	40,174,776	35,927,985
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Issued	0	0
Treasury Stock, Shares	20,220	21,643

Consolidated Statements of Oper

Consolidated Statements of Operations (Audited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Natural gas, NGL and crude oil sales	$ 103,193	$ 104,483	$ 96,928	$ 74,109	$ 99,857	$ 120,526	$ 131,017	$ 120,013	$ 378,713	$ 471,413	$ 340,795
Sales from natural gas marketing	2,584	2,580	2,523	3,233	8,922	13,297	22,415	26,937	10,920	71,571	69,787
Commodity price risk management gain (loss), net	62,013	123,549	(49,041)	66,662	297,643	90,213	(52,643)	(24,909)	203,183	310,304	(23,919)
Well operations, pipeline income and other	844	488	550	628	1,269	520	514	616	2,510	2,919	6,002
Total revenues	168,634	231,100	50,960	144,632	407,691	224,556	101,303	122,657	595,326	856,207	392,665
Costs, expenses and other:
Lease operating expenses	14,244	13,824	12,639	16,285	11,050	11,020	11,961	8,371	56,992	42,402	33,817
Production taxes	5,237	5,476	3,837	3,893	2,950	8,724	7,551	6,390	18,443	25,615	21,758
Transportation, gathering and processing expenses	3,567	3,938	1,308	1,338	1,331	1,208	818	1,235	10,151	4,592	5,152
Cost of natural gas marketing	2,842	2,781	2,836	3,258	9,370	13,347	22,428	26,870	11,717	72,015	70,084
Exploration expense	290	252	275	285	174	190	276	307	1,102	947	6,334
Impairment of natural gas and crude oil properties	413	154,031	4,404	2,772	161,914	1,962	2,019	952	161,620	166,847	52,873
General and administrative expense	27,908	20,278	20,728	21,045	20,989	36,328	41,713	24,529	89,959	123,559	63,715
Depreciation, depletion and amortization	96,385	80,947	70,106	55,820	50,363	49,640	49,636	42,889	303,258	192,528	115,624
Accretion of asset retirement obligations	1,551	1,594	1,588	1,560	873	861	840	841	6,293	3,415	4,566
(Gain) loss on sale of Leaseholds	(83)	(74)	(207)	(21)	(70)	21	(23)	579	(385)	507	2,022
Total cost, expenses and other	152,354	283,047	117,514	106,235	258,944	123,301	137,219	112,963	659,150	632,427	375,945
Income from operations	16,280	(51,947)	(66,554)	38,397	148,747	101,255	(35,916)	9,694	(63,824)	223,780	16,720
Interest expense	(12,187)	(12,092)	(11,567)	(11,725)	(11,643)	(11,821)	(12,195)	(12,183)	(47,571)	(47,842)	(50,143)
Interest income	1,181	1,378	1,135	1,113	981	39	83	187	4,807	1,290	460
Income (loss) from continuing operations before income taxes	5,274	(62,661)	(76,986)	27,785	138,085	89,473	(48,028)	(2,302)	(106,588)	177,228	(32,963)
Provision for income taxes	(2,252)	21,167	30,116	(10,723)	(54,115)	(35,396)	18,650	894	38,308	(69,967)	11,852
Income (loss) from continuing operations	3,022	(41,494)	(46,870)	17,062	83,970	54,077	(29,378)	(1,408)	(68,280)	107,261	(21,111)
Income (loss) from discontinued operations, net of tax	0	0	0	0	47,782	(80)	1,191	(719)	0	48,174	(1,190)
Net income (loss)	$ 3,022	$ (41,494)	$ (46,870)	$ 17,062	$ 131,752	$ 53,997	$ (28,187)	$ (2,127)	$ (68,280)	$ 155,435	$ (22,301)
Basic
Income (loss) from continuing operations	$ 0.08	$ (1.04)	$ (1.17)	$ 0.47	$ 2.34	$ 1.51	$ (0.82)	$ (0.04)	$ (1.74)	$ 3	$ (0.65)
Income (loss) from discontinued operations	0	0	0	0	1.33	0	0.03	(0.02)	0	1.34	(0.04)
Net income (loss) attributable to shareholders	0.08	(1.04)	(1.17)	0.47	3.67	1.51	(0.79)	(0.06)	(1.74)	4.34	(0.69)
Diluted
Income (loss) from continuing operations	0.07	(1.04)	(1.17)	0.46	2.32	1.47	(0.82)	(0.04)	(1.74)	2.93	(0.65)
Income (loss) from discontinued operations	0	0	0	0	1.32	0	0.03	(0.02)	0	1.31	(0.04)
Net income (loss) attributable to shareholders	$ 0.07	$ (1.04)	$ (1.17)	$ 0.46	$ 3.64	$ 1.47	$ (0.79)	$ (0.06)	$ (1.74)	$ 4.24	$ (0.69)
Weighted-average common shares outstanding:
Basic	40,094	40,085	40,035	36,349	35,847	35,834	35,762	35,690	39,153	35,784	32,426
Diluted	41,264	40,085	40,035	36,981	36,146	36,828	35,762	35,690	39,153	36,678	32,426

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Audited) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (68,280,000)	$ 155,435,000	$ (22,301,000)
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled derivatives	35,791,000	(311,281,000)	36,801,000
Depreciation, depletion and amortization	303,258,000	201,656,000	129,518,000
Impairment of natural gas and crude oil properties	161,620,000	167,280,000	53,802,000
Accretion of asset retirement obligation	6,293,000	3,455,000	4,747,000
Stock-based compensation	20,068,000	17,518,000	12,880,000
Excess tax benefits from stock-based compensation	(1,361,000)	(1,999,000)	(2,489,000)
(Gain) loss from sale of properties and equipment	385,000	75,972,000	(3,722,000)
Amortization of debt discount and issuance costs	7,040,000	6,938,000	6,783,000
Deferred income taxes	(41,415,000)	88,474,000	(15,883,000)
Inventory adjustment and other	(1,855,000)	(1,329,000)	170,000
Total adjustments to net income (loss) to reconcile to net cash provided by operating activities:	489,054,000	94,740,000	230,051,000
Changes in current assets and liabilities:
Accounts receivable	24,769,000	(34,598,000)	(41,509,000)
Other assets	(2,264,000)	(3,296,000)	3,461,000
Restricted cash	46,000	2,214,000	(8,000)
Production tax liability	(1,629,000)	3,358,000	4,121,000
Accounts payable and accrued expenses	(30,310,000)	21,453,000	(11,485,000)
Other liabilities	(313,000)	(2,617,000)	(3,165,000)
Total changes in current assets and liabilities	(9,701,000)	(13,486,000)	(48,585,000)
Net cash provided by operating activities	411,073,000	236,689,000	159,165,000
Cash flows from investing activities:
Capital expenditures	(604,668,000)	(628,592,000)	(394,948,000)
Acquisition of natural gas and crude oil properties, net of cash acquired	0	0	(9,658,000)
Proceeds from acquisition adjustments	0	0	7,579,000
Proceeds from sale of properties and equipment	405,000	154,457,000	179,919,000
Net cash used in investing activities	(604,263,000)	(474,135,000)	(217,108,000)
Cash flows from financing activities:
Proceeds from credit facility	397,000,000	263,750,000	260,250,000
Payment of credit facility	416,000,000	200,000,000	283,500,000
Payment of debt issuance costs	(974,000)	(88,000)	(2,352,000)
Proceeds from sale of equity, net of issuance costs	202,851,000	0	275,847,000
Excess tax benefits from stock-based compensation	1,361,000	1,999,000	2,489,000
Purchase of treasury stock	(6,056,000)	(5,392,000)	(4,133,000)
Principal payments under capital lease obligations	(208,000)	0	0
Proceeds from exercise of stock options	0	0	128,000
Net cash provided by (used in) financing activities	177,974,000	60,269,000	248,729,000
Net increase (decrease) in cash and cash equivalents	(15,216,000)	(177,177,000)	190,786,000
Cash and cash equivalents, beginning of year	16,066,000	193,243,000	2,457,000
Cash and cash equivalents, end of year	850,000	16,066,000	193,243,000
Cash payments (receipts) for:
Interest, net of capitalized interest	45,642,000	46,809,000	48,844,000
Income taxes	10,049,000	1,800,000	(3,014,000)
Non-cash investing activities:
Change in accounts payable related to purchases of properties and equipment	(45,230,000)	39,667,000	33,328,000
Change in asset retirement obligation, with a corresponding increase to natural gas and crude oil properties, net of disposals	14,030,000	33,250,000	2,112,000
Change in accounts receivable related to disposition of properties and equipment	0	0	808,000
Change in other assets related to disposition of properties and equipment	0	39,048,000	3,350,000
Purchase of properties and equipment under capital leases	$ 1,601,000	$ 0	$ 0

Consolidated Statement of Equit

Consolidated Statement of Equity (Statement) - USD ($)	Total	Parent [Member]	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued				30,294,224			5,059
Shares issued pursuant to sale of equity				5,175,000
Exercise of stock options				10,763
Issuance of stock awards, net of forfeitures				212,926
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Retirement of treasury shares				(17,257)			(17,257)
Purchase of treasury shares							84,642
Issuance of treasury shares							(67,334)
Non-employee directors' deferred compensation plan							398
Shares end of year at Dec. 31, 2013				35,670,148
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2012			$ 0	$ 303,000	$ 387,494,000	$ 315,568,000	$ (184,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity				52,000	275,795,000
Purchase of treasury shares							(4,133,000)
Issuance of stock awards, net of forfeitures				2,000
Exercise of stock options					125,000
Share-based Compensation expense	$ 12,880,000				12,402,000
Issuance of treasury shares					(3,270,000)		3,271,000
Retirement of treasury shares					(824,000)		824,000
Tax benefit (detriment) of stock-based compensation					2,489,000
Non-employee directors' deferred compensation plan							(19,000)
Net income (Loss) attributable to shareholders	(22,301,000)					(22,301,000)
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2013		$ 967,594,000	0	$ 357,000	674,211,000	293,267,000	$ (241,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued				35,675,656			5,508
Shares issued pursuant to sale of equity				0
Exercise of stock options				0
Issuance of stock awards, net of forfeitures				253,032
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Retirement of treasury shares				(703)			(703)
Purchase of treasury shares							97,646
Issuance of treasury shares							(83,208)
Non-employee directors' deferred compensation plan							2,400
Shares end of year at Dec. 31, 2014				35,906,342
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity				$ 0	0
Purchase of treasury shares							$ (5,392,000)
Issuance of stock awards, net of forfeitures				2,000
Exercise of stock options					0
Share-based Compensation expense	17,518,000				17,851,000
Issuance of treasury shares					(4,817,000)		4,817,000
Retirement of treasury shares					(35,000)		35,000
Tax benefit (detriment) of stock-based compensation					1,999,000
Non-employee directors' deferred compensation plan							(130,000)
Net income (Loss) attributable to shareholders	155,435,000					155,435,000
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2014		1,137,359,000	$ 0	$ 359,000	689,209,000	448,702,000	$ (911,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued				35,927,985			21,643
Shares issued pursuant to sale of equity				4,002,000
Exercise of stock options				7,720
Issuance of stock awards, net of forfeitures				237,071
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Retirement of treasury shares				0			0
Purchase of treasury shares							120,864
Issuance of treasury shares							(127,159)
Non-employee directors' deferred compensation plan							4,872
Shares end of year at Dec. 31, 2015				40,154,556
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity				$ 40,000	202,811,000
Purchase of treasury shares							$ (6,055,000)
Issuance of stock awards, net of forfeitures				3,000
Exercise of stock options					0
Share-based Compensation expense	20,068,000				20,207,000
Issuance of treasury shares					(6,206,000)		6,206,000
Retirement of treasury shares					0		0
Tax benefit (detriment) of stock-based compensation					1,361,000
Non-employee directors' deferred compensation plan							(249,000)
Net income (Loss) attributable to shareholders	$ (68,280,000)					(68,280,000)
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2015		$ 1,287,197,000		$ 402,000	$ 907,382,000	$ 380,422,000	$ (1,009,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued				40,174,776			20,220

NATURE OF OPERATIONS AND BASIS

NATURE OF OPERATIONS AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2015
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract]
Nature of Operations [Text Block]	NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. (the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs, with primary operations in the Wattenberg Field in Colorado and the Utica Shale in southeastern Ohio. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Ohio operations are focused in the Utica Shale play. As of December 31, 2015 , we owned an interest in approximately 3,000 gross wells. We are engaged in two business segments: Oil and Gas Exploration and Production and Gas Marketing. In October 2014 , we sold our entire 50% ownership interest in our joint venture, PDCM, to an unrelated third-party. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. The accompanying audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiary Riley Natural Gas ("RNG"), our proportionate share of our four affiliated partnerships and, for the year ended December 31, 2014 and 2013, our proportionate share of PDCM. As of December 31, 2015 , we had four remaining affiliated partnerships that continue to conduct crude oil and natural gas producing activities. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves, future cash flows from crude oil and natural gas properties, valuation of derivative instruments, impairment of proved and unproved properties and valuation of deferred income tax assets. During the fourth quarter of 2015, we reclassified certain amounts within our costs and expenses in the consolidated statements of operations and assets and liabilities in the consolidated balance sheets. Specifically, production costs has been segregated into lease operating expenses, production taxes and transportation, gathering and processing expenses. This reclassification has been made to prior period financial statements to conform to the current year presentation. We believe these changes allow users of our financial statements to better understand our expense structure and make our financial statements more comparable to those of peer companies. Further, we have noted the following misclassifications in prior year filings, which have been corrected in the current year presentation: • Production-related general and administrative costs totaling $7.7 million and $3.8 million for 2014 and 2013, respectively, have been reclassified from production costs to general and administrative expense; • Prepaid well costs write-offs totaling $3.3 million and $0.4 million for 2014 and 2013, respectively, have been reclassified from production costs to impairment of crude oil and natural gas properties; and • Prepaid well costs totaling $27.3 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets to properties and equipment, net; We evaluated the impact of these misclassifications and determined they were not material to the prior periods presented. Additionally, as a result of adopting the accounting standards update on the balance sheet classification of debt issuance costs and deferred taxes, the following reclassifications have been made to the prior period financial statements: • Debt issuance costs totaling $9.4 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets and are presented as a direct deduction from the carrying amount of long-term debt; and • Current deferred income tax liabilities totaling $59.2 million in the December 31, 2014 consolidated balance sheet have been reclassified to non-current pursuant to the income tax accounting standards update issued and adopted in 2015. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity.

RECENT ACCOUNTING STANDARDS

RECENT ACCOUNTING STANDARDS	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. Restricted Cash. We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2015 and 2014 , we had collateral in the form of certificates of deposit and cash totaling $0.7 million included in other assets. Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our crude oil and natural gas operations. As of December 31, 2015 and 2014 , inventory of $0.6 million and $0.8 million , respectively, is included in prepaid expenses and other current assets on the consolidated balance sheets. Additionally, as of December 31, 2015 , inventory for the White Cliffs pipeline line fill of $1.1 million is included in other assets on the consolidated balance sheets. Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of crude oil and natural gas derivative instruments for speculative purposes. All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled derivatives depends on the purpose for issuing or holding the derivative. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2015 and 2014 , respectively. Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment , for disclosures related to changes in our capitalized exploratory well costs, if any. Proved Property Impairment. Upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statements of operations line item impairment of crude oil and natural gas properties, with a corresponding impact on accumulated DD&A on the consolidated balance sheets. Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of crude oil and natural gas properties. Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. There were no impairments to other property and equipment in 2015 and 2013 , respectively. Total impairments to other property and equipment was $0.8 million in 2014 . The following table presents the estimated useful lives of our other property and equipment: Transportation and other equipment 3 - 20 years Buildings 20 - 30 years Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $4.5 million , $4.1 million and $4.0 million in 2015 , 2014 and 2013 , respectively. Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $5.1 million , $3.5 million and $1.7 million in 2015 , 2014 and 2013 , respectively. Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations. Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed and included in the statement of operations line item production taxes. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $19.0 million and $26.4 million in December 31, 2015 and 2014 , respectively. Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2015 and 2014 , we had no valuation allowance. Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs capitalized as of December 31, 2015 and 2014 were $11.4 million and $13.7 million , respectively. The December 31, 2015 amount included $0.2 million in costs related to the issuance of our 3.25% convertible senior notes due 2016 and $7.6 million related to our 7.75% senior notes due 2022, both shown as a reduction in the related debt, and $3.6 million related to our revolving credit facility shown as a long-term asset. The December 31, 2014 amount included $0.7 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $8.7 million related to our 7.75% senior notes due 2022 and $4.3 million related to our revolving credit facility. Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 10, Asset Retirement Obligations , for a reconciliation of the changes in our asset retirement obligation. Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. Crude oil, natural gas and NGLs sales. Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. Our crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the transportation method used. We use the "net-back" method of accounting for natural gas and NGLs, as well as a portion of our crude oil production, from the Wattenberg Field and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the "gross" method of accounting for Wattenberg Field crude oil delivered through the White Cliffs pipeline and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering or processing services. Under this method, we recognize revenues based on the gross selling price. Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, RNG, suppliers and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled derivatives of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the affiliated partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured. Accounting for Acquisitions. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2015 , 2014 and 2013 . Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. Interest Income. Interest income on our note receivable is recognized over its term using the effective interest method. Recently Adopted Accounting Standards. In November 2014, the FASB issued an update to accounting for derivatives and hedging instruments. The update clarifies how current accounting guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the accounting update clarifies that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the update clarifies that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The assessment of the substance of the relevant terms and features should incorporate a consideration of the characteristics of the terms and features themselves, the circumstances under which the hybrid financial instrument was issued or acquired, and the potential outcomes of the hybrid financial instrument, as well as the likelihood of those potential outcomes. The accounting update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In February 2015, the FASB issued an accounting update modifying existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2015, and require either a retrospective or a modified retrospective approach to adoption. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In April 2015, the FASB issued an accounting update simplifying the presentation of debt issuance costs and requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The update did not affect the recognition and measurement guidance for debt issuance costs. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. See Note 1, Nature of Operations and Basis of Presentation, for the amounts reclassified in the December 31, 2014 consolidated balance sheet. In July 2015, the FASB issued an accounting update requiring all entities to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In September 2015, the FASB issued an accounting update requiring adjustments to provisional amounts that are identified during the measurement period of a business combination to be recognized in the reporting period in which the adjustment amounts are determined. The accounting update also requires an entity to present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current-period earnings, by line item, that would have been recorded in previous reporting periods if the adjustment to the estimated amounts had been recognized as of the acquisition date. This guidance is effective for public entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The accounting update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In November 2015, the FASB issued an accounting update simplifying the presentation of deferred income taxes by requiring that all deferred tax liabilities and assets, along with any related valuation allowance, be classified as non-current in a classified statement of financial position. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. See Note 1, Nature of Operations and Basis of Presentation, for the amounts reclassified in the December 31, 2014 consolidated balance sheet. Recently Issued Accounting Standards. In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when (or as) each performance obligation is satisfied. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are currently evaluating the impact these changes may have on our consolidated financial statements. In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on our consolidated financial statements.

FAIR VALUE MEASUREMENTS AND DIS

FAIR VALUE MEASUREMENTS AND DISCLOSURES	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value, Measurement Inputs, Disclosure [Text Block]	FAIR VALUE OF FINANCIAL INSTRUMENTS Derivative Financial Instruments Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our collars and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: As of December 31, 2015 2014 Significant Other Significant Total Significant Other Significant Total (in thousands) Assets: Commodity-based derivative contracts $ 174,657 $ 91,288 $ 265,945 $ 237,939 $ 62,356 $ 300,295 Basis protection derivative contracts 101 — 101 19 — 19 Total assets 174,758 91,288 266,046 237,958 62,356 300,314 Liabilities: Commodity-based derivative contracts 738 — 738 742 — 742 Basis protection derivative contracts 1,552 — 1,552 25 — 25 Total liabilities 2,290 — 2,290 767 — 767 Net asset $ 172,468 $ 91,288 $ 263,756 $ 237,191 $ 62,356 $ 299,547 The following table presents a reconciliation of our Level 3 assets measured at fair value: 2015 2014 2013 (in thousands) Fair value, net asset beginning of period $ 62,356 $ 1,111 $ 13,610 Changes in fair value included in statement of operations line item: Commodity price risk management gain (loss), net 65,018 62,003 (1,748 ) Sales from natural gas marketing 146 (22 ) 13 Settlements included in statement of operations line items: Commodity price risk management gain (loss), net (36,169 ) (737 ) (6,361 ) Sales from natural gas marketing (63 ) 1 (37 ) Loss from discontinued operations, net of tax — — (4,366 ) Fair value, net asset end of period $ 91,288 $ 62,356 $ 1,111 Net change in fair value of unsettled derivatives included in statement of operations line item: Commodity price risk management gain (loss), net $ 43,540 $ 15,632 $ (2,731 ) Sales from natural gas marketing — 3 4 Total $ 43,540 $ 15,635 $ (2,727 ) The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts. Non-Derivative Financial Assets and Liabilities The carrying value of the financial instruments included in current assets and current liabilities, excluding the current portion of long-term debt, approximate fair value due to the short-term maturities of these instruments. See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how we determined fair value for these assets and liabilities. The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was immaterial as of December 31, 2015 and 2014 . The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, as of December 31, 2015 , we estimate the fair value of the portion of our long-term debt related to our 3.25% convertible senior notes due 2016 to be $150.2 million , or 130.6% of par value, and the portion related to our 7.75% senior notes due 2022 to be $485.0 million , or 97.0% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the vehicle lease.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	DERIVATIVE FINANCIAL INSTRUMENTS Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments. • For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and • For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2015 , we had derivative instruments, which were comprised of collars, fixed-price swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 77,320 BBtu of natural gas and 5,580 MBbls of crude oil. The majority of our derivative contracts are entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices. As of December 31, 2015 , our derivative instruments were comprised of commodity swaps, collars, basis protection swaps and physical sales and purchases. • Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; • Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; • Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2015 , we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and • Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. We have elected not to designate any of our derivative instruments as hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2015 and 2014 : Derivative instruments: Balance sheet line item 2015 2014 (in thousands) Derivative assets: Current Commodity contracts Related to crude oil and natural gas sales Fair value of derivatives $ 221,161 $ 186,886 Related to natural gas marketing Fair value of derivatives 441 590 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 57 19 221,659 187,495 Non-current Commodity contracts Related to crude oil and natural gas sales Fair value of derivatives 44,292 112,599 Related to natural gas marketing Fair value of derivatives 51 220 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 44 — 44,387 112,819 Total derivative assets $ 266,046 $ 300,314 Derivative liabilities: Current Commodity contracts Related to natural gas marketing Fair value of derivatives $ 417 $ 545 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 1,178 25 1,595 570 Non-current Commodity contracts Related to crude oil and natural gas sales Fair value of derivatives 275 — Related to natural gas marketing Fair value of derivatives 46 197 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 374 — 695 197 Total derivative liabilities $ 2,290 $ 767 The following table presents the impact of our derivative instruments on our consolidated statements of operations: Year Ended December 31, Consolidated statement of operations line item 2015 2014 2013 (in thousands) Commodity price risk management gain (loss), net Net settlements $ 238,935 $ (837 ) $ 11,177 Net change in fair value of unsettled derivatives (35,752 ) 311,141 (35,096 ) Total commodity price risk management gain (loss), net $ 203,183 $ 310,304 $ (23,919 ) Sales from natural gas marketing Net settlements $ 778 $ (208 ) $ 446 Net change in fair value of unsettled derivatives (318 ) 364 429 Total sales from natural gas marketing $ 460 $ 156 $ 875 Cost of natural gas marketing Net settlements $ (745 ) $ 346 $ (257 ) Net change in fair value of unsettled derivatives 279 (451 ) (412 ) Total cost of natural gas marketing $ (466 ) $ (105 ) $ (669 ) All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of December 31, 2015 Derivative instruments, recorded in consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 266,046 $ (1,921 ) $ 264,125 Liability derivatives: Derivative instruments, at fair value $ 2,290 $ (1,921 ) $ 369 As of December 31, 2014 Derivative instruments, recorded in consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 300,314 $ (29 ) $ 300,285 Liability derivatives: Derivative instruments, at fair value $ 767 $ (29 ) $ 738

CONCENTRATION OF RISK

CONCENTRATION OF RISK	12 Months Ended
	Dec. 31, 2015
Concentration Risks, Types, No Concentration Percentage [Abstract]
Concentration Risk Disclosure [Text Block]	CONCENTRATION OF RISK Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: As of December 31, 2015 2014 (in thousands) Crude oil, natural gas and NGLs sales $ 41,873 $ 49,531 Joint interest billings 35,017 52,841 Derivative counterparties 24,437 12,582 Insurance reimbursement 879 11,212 Other 4,077 5,524 Allowance for doubtful accounts (2,009 ) (486 ) Accounts receivable, net $ 104,274 $ 131,204 Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, other third parties that own working interests in the properties we operate and derivative counterparties. For the years ended December 31, 2015 , 2014 and 2013 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2015 , we had one customer representing 10% or greater of our accounts receivable balance. Concord Energy represents 11.3% of our December 31, 2015 accounts receivable balance. As of December 31, 2014 , we had two customers representing 10% or greater of our accounts receivable balance. Suncor Energy Marketing, Inc. and Concord Energy represented 11.1% and 10.3% , respectively. Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: Year Ended December 31, Customer 2015 2014 2013 Concord Energy 23.2 % 18.3 % — % Suncor Energy Marketing, Inc. 14.3 % 19.7 % 35.9 % Shell Trading Company 13.8 % — % — % DCP Midstream, LP 13.2 % 15.1 % 13.9 % Teppco Crude Oil, LLC — % 12.9 % 8.0 % The concentration of revenue represented by the customers noted above relate to our oil and gas exploration and production segment. Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2015 , taking into account the estimated likelihood of nonperformance. The following table presents the counterparties that expose us to credit risk as of December 31, 2015 , with regard to our derivative assets: Fair Value of Counterparty Name As of December 31, 2015 (in thousands) Canadian Imperial Bank of Commerce (1) $ 78,102 JP Morgan Chase Bank, N.A (1) 71,012 Bank of Nova Scotia (1) 49,758 Wells Fargo Bank, N.A. (1) 32,474 NATIXIS (1) 29,754 Other lenders in our revolving credit facility 4,856 Other (2) 90 Total $ 266,046 ____________ (1) Major lender in our revolving credit facility. See Note 8, Long-Term Debt. (2) Represents one counterparty. Note Receivable The following table presents information regarding our note receivable outstanding as of December 31, 2015 : Amount (in thousands) Note receivable: Principal outstanding, December 31, 2014 $ 39,707 Paid-in-kind interest 3,362 Principal outstanding, December 31, 2015 $ 43,069 In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations , for additional information regarding the sale. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million , bearing varying interest rates beginning at 8% and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of December 31, 2015 , the issuer of the Note had elected the PIK Interest option for each quarterly period since inception. The principal and any unpaid interest shall be due and payable in full in September 2020 and can be prepaid in whole or in part at any time, and in certain circumstances must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets. Under the effective interest method, we recognized $4.5 million and $0.9 million of interest income for the years ended December 31, 2015 and 2014 , respectively, of which $3.4 million and $0.7 million , respectively, was PIK Interest. As of December 31, 2015 and 2014, the $43.1 million and $39.7 million , respectively, outstanding balance on the Note was included in the consolidated balance sheet line item other assets.

PROPERTIES AND EQUIPMENT

PROPERTIES AND EQUIPMENT	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure [Text Block]	PROPERTIES AND EQUIPMENT The following table presents the components of properties and equipment, net of accumulated DD&A: As of December 31, 2015 2014 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 2,881,189 $ 2,267,165 Unproved 60,498 188,206 Total crude oil and natural gas properties 2,941,687 2,455,371 Equipment and other 30,098 29,562 Land and buildings 9,015 9,015 Construction in progress 113,115 165,205 Properties and equipment, at cost 3,093,915 2,659,153 Accumulated DD&A (1,156,237 ) (831,699 ) Properties and equipment, net $ 1,937,678 $ 1,827,454 The following table presents impairment charges recorded for crude oil and natural gas properties: Year Ended December 31, 2015 2014 2013 (in thousands) Continuing operations: Impairment of proved and unproved properties $ 154,608 $ 161,604 $ 49,631 Amortization of individually insignificant unproved properties 7,012 4,465 3,242 Other — 778 — Total continuing operations 161,620 166,847 52,873 Discontinued operations: Impairment of proved and unproved properties — 433 566 Amortization of individually insignificant unproved properties — — 363 Total discontinued operations — 433 929 Total impairment of crude oil and natural gas properties $ 161,620 $ 167,280 $ 53,802 In 2015, due to a significant decline in commodity prices and a decrease in net-back realizations, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded an impairment charge of $150.3 million to write-down our Utica Shale proved and unproved properties. Of this impairment charge, $24.7 million was recorded to write-down certain capitalized well costs on our Utica Shale proved producing properties. This impairment charge represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $27.9 million , excluding estimated salvage value, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Additionally, as a result of the current outlook for future commodity prices, we recorded an impairment charge of $125.6 million to write-down all of our Utica Shale lease acquisition costs and pad development costs for pads not in production. These impairment charges were included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. In 2014, we recognized an impairment charge of $158.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value, $112.6 million of which was for capitalized well costs on proved producing properties and $45.7 million for capitalized leasehold costs on unproved properties. The impairment charge represented the amount by which the carrying value of the Utica Shale crude oil and natural gas properties exceeded the estimated fair value and was therefore not recoverable. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. In 2013, we recognized an impairment charge of approximately $48.8 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania previously owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less the cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties. Suspended Well Costs As of December 31, 2015 and 2014 , there were no suspended well costs or wells pending determination.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES The table below presents the components of our provision for income taxes from continuing operations for the years presented: Year Ended December 31, 2015 2014 2013 (in thousands) Current: Federal $ (2,944 ) $ (1,514 ) $ 1,355 State (163 ) 966 199 Total current income taxes (3,107 ) (548 ) 1,554 Deferred: Federal 37,352 (60,698 ) 8,238 State 4,063 (8,721 ) 2,060 Total deferred income taxes 41,415 (69,419 ) 10,298 Income tax benefit (expense) from continuing operations $ 38,308 $ (69,967 ) $ 11,852 In the last three years, we continued to utilize tax deferral strategies such as bonus depreciation, accelerated depreciation and intangible drilling cost ("IDC") expense elections or accelerated IDC amortization to minimize our current taxes. In 2013 these deferral strategies enabled us to offset any taxable gain on the sale of our non-core Colorado assets and also preserved some of our NOLs to carry forward for use against our anticipated 2014 taxable income. In 2014, these same deferral strategies, along with carried forward federal and state NOLs, credits, and suspended deductions, permitted us to offset the majority of the tax gain on the sale of PDCM. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale of our non-core Colorado assets and the sale of our entire 50% ownership interest in PDCM. In 2015, these continued deferral strategies offset the tax adjustments for impairments to crude oil and natural gas properties and negative net change in fair value of unsettled derivatives to enable our current income taxes to be minimized. The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: Year Ended December, 31, 2015 2014 2013 Statutory tax rate 35.0 % 35.0 % 35.0 % State income tax, net 2.4 2.8 4.0 Percentage depletion 0.3 (0.3 ) 2.2 Non-deductible compensation (1.2 ) 0.7 (4.2 ) Other (0.6 ) 1.3 (1.0 ) Effective tax rate 35.9 % 39.5 % 36.0 % The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2015 and 2014 are presented below: As of December 31, 2015 2014 (in thousands) Deferred tax assets: Deferred compensation $ 13,104 $ 10,459 Asset retirement obligations 34,101 28,051 State NOL and tax credit carryforwards, net 3,376 3,761 Alternative minimum tax - credit carryforward 2,812 2,906 Settlement of class action litigation — 12,259 Other 3,412 3,144 Deferred tax assets 56,805 60,580 Deferred tax liabilities: Properties and equipment 99,191 130,155 Net change in fair value of unsettled derivatives 100,369 113,007 Convertible debt 697 2,285 Total gross deferred tax liabilities 200,257 245,447 Net deferred tax liability $ 143,452 $ 184,867 Deferred tax assets decreased in 2015, primarily due to the reclassification of the deferred tax asset associated with the settlement of certain partnership-related class action litigation to properties and equipment. The cost of the settlement of this litigation has been capitalized to the value of crude oil and natural gas properties for income tax purposes. Deferred tax liabilities for properties and equipment decreased as a result of the increase in the deferred tax asset for the impairment of some of our crude oil and natural gas properties and the reclassification of the deferred asset for litigation settlement. Both of these deferred tax assets relate to the tax basis of our crude oil and natural gas properties and are therefore netted against the deferred tax liability. This decrease from impairments and litigation settlement was partially offset by our continued use of statutory provisions for expensing and accelerated amortization of IDCs and accelerated tax depreciation. In addition, the fair value of unsettled derivatives at December 31, 2015 decreased and resulted in a decrease to our unrealized tax gain versus a larger unrealized tax gain at December 31, 2014. As of December 31, 2015 , we have state NOL carryforwards of $74.3 million that begin to expire in 2030 and state credit carryforwards of $1.6 million that begin to expire in 2022 . Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2015 . The total amount of unrecognized tax benefits that would affect the effective tax rate increased to $0.1 million in the current year due to interest recorded on a tax filing position related to our 2014 federal tax return which the IRS is in disagreement with at December 31, 2015. The statute of limitations for most of our state tax jurisdictions is open from 2011 forward. In accordance with the CAP program, the IRS completed its “post filing review” of our 2013 tax return in January 2015 and issued a “no change” letter for the reviewed tax year. The IRS has not completed its “post filing review” of our 2014 return as one “un-agreed issue” remained at December 31, 2015. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. We are currently participating in the CAP program for the review of our 2014 and 2015 tax years and we have been invited and have accepted continued participation in the program for our 2016 tax year. Participation in the CAP program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. As of December 31, 2015 , we were current with our income tax filings in all applicable state jurisdictions. In 2013, the State of Colorado examined our 2008 through 2011 Colorado corporate income tax returns and proposed no adjustments.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT Long-term debt consists of the following: As of December 31, 2015 2014 (in thousands) Senior notes: 3.25% Convertible senior notes due 2016: Principal amount $ 115,000 $ 115,000 Unamortized discount (1,852 ) (6,077 ) Unamortized debt issuance costs (208 ) (765 ) 3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs 112,940 108,158 7.75% Senior notes due 2022: Principal amount 500,000 500,000 Unamortized debt issuance costs (7,563 ) (8,683 ) 7.75% Senior notes due 2022, net of unamortized debt issuance costs 492,437 491,317 Total senior notes 605,377 599,475 Revolving credit facility 37,000 56,000 Total debt, net of discount and unamortized debt issuance costs 642,377 655,475 Less current portion of long-term debt 112,940 — Long-term debt $ 529,437 $ 655,475 Senior Notes 3.25% Convertible Senior Notes Due 2016. In November 2010 , we issued $115 million aggregate principal amount 3.25% convertible senior notes due 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is May 15, 2016 . Interest is payable semi-annually in arrears on each May 15 and November 15 . The Convertible Notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the Convertible Notes; equal in right of payment to our existing and future unsecured indebtedness that is not expressly subordinated (including our 2022 Senior Notes); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our revolving credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the Convertible Notes contains certain non-financial covenants. The Convertible Notes and the common stock issuable upon conversion of the Convertible Notes, if any, have not been registered under the Securities Act of 1933 or any state securities laws, nor are we required to register such Convertible Notes or common shares. The Convertible Notes are governed by an indenture between the Company and the Bank of New York Mellon, as trustee. Beginning in November 15, 2015 , holders of the Convertible Notes may convert the notes at an initial conversion rate of 23.5849 shares per $1,000 principal amount, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, we have elected to settle the principal amount of the Convertible Notes in cash and settle the excess conversion value in shares, as well as cash in lieu of fractional shares, in May 2016. We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued the Convertible Notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the Convertible Notes. As of December 31, 2015 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the Convertible Notes of 0.4 years using an effective interest rate of 7.4% . For 2015 , interest expense related to the indebtedness and the amortization of the discount was $3.7 million and $4.2 million , respectively, compared to $3.7 million and $3.9 million , respectively, in 2014 and $3.7 million each in 2013 . As of December 31, 2015 , the principal amount exceeded the “if-converted” value of the Convertible Notes by approximately $29.8 million . 7.75% Senior Notes Due 2022. In October 2012 , we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional buyers. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 . Approximately $11 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness (including our Convertible Notes) and rank effectively junior in right of payment to all of our secured indebtedness (to the extent of the value of the collateral securing such indebtedness), including borrowings under our revolving credit facility. In connection with the issuance of the 2022 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for substantially identical registered notes and to use commercially reasonable efforts to cause the exchange offer to be completed on or prior to September 28, 2013. The registration statement was declared effective by the SEC in July 2013 and the exchange offer was completed in August 2013. At any time prior to October 15, 2017 , we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture, and on or after October 15, 2017 , we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase. The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company. As of December 31, 2015 , we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next 12-month period. Credit Facility Revolving Credit Facility . In September 2015 , we entered into a Second Amendment to Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. This agreement amends and restates the credit agreement dated November 2010 and extends the maturity of the revolving credit facility to May 2020 . The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. In September 2015, we completed the semi-annual redetermination of our revolving credit facility, which resulted in the reaffirmation of our borrowing base at $700 million ; however, we have elected to maintain the aggregate commitment at $450 million . The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility. We had an outstanding balance of $37.0 million on our revolving credit facility as of December 31, 2015 compared to $56.0 million outstanding as of December 31, 2014 . The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.6% and 3.8% per annum as of December 31, 2015 and 2014 , respectively. The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires in May 2020 , or in the event that the borrowing base falls below the outstanding balance. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of December 31, 2015 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the Convertible Notes. Among other things, the restriction on redemption of the Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility must exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million. As of December 31, 2015 , RNG had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit currently expires in September 2016 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of December 31, 2015 , the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $401.3 million . In addition to our currently elected commitment of $450 million , we have an additional $250 million of borrowing base availability under the revolving credit facility, subject to certain terms and conditions of the agreement.

CAPITAL LEASES (Notes)

CAPITAL LEASES (Notes)	12 Months Ended
	Dec. 31, 2015
Capital Leases [Abstract]
Capital Leases in Financial Statements of Lessee Disclosure [Text Block]	CAPITAL LEASES Beginning in the first quarter of 2015, we entered into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. Each lease agreement has a term of three years and is being accounted for as a capital lease, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90% of the fair value of the leased vehicles at inception of the lease. The following table presents leased vehicles under capital leases as of December 31, 2015 : Amount (in thousands) Vehicles $ 1,601 Accumulated depreciation (211 ) $ 1,390 Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: For the Twelve Months Ending December 31, Amount (in thousands) 2016 $ 492 2017 492 2018 681 1,665 Less executory cost (70 ) Less amount representing interest (202 ) Present value of minimum lease payments $ 1,393 Short-term capital lease obligations $ 357 Long-term capital lease obligations 1,036 $ 1,393 Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	ASSET RETIREMENT OBLIGATIONS The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: 2015 2014 (in thousands) Balance at beginning of period, January 1, 2015 $ 73,855 $ 41,030 Revisions in estimated cash flows 11,658 31,945 Obligations incurred with development activities 2,373 1,170 Accretion expense 6,293 3,455 Obligations discharged with asset retirements (4,687 ) (3,745 ) Balance end of period, December 31, 2015 89,492 73,855 Less current portion (5,460 ) (1,863 ) Long-term portion $ 84,032 $ 71,992 Our estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2015, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 7.6% to 8.0%. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. The revisions in estimated cash flows during 2015 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. The increase in the current portion of asset retirement obligations in 2015 is attributable to a decrease in the estimated useful life of certain vertical wells in the Wattenberg Field and an increase in the number of wells to be plugged and abandoned to allow for the drilling of nearby horizontal wells. The revisions in estimated cash flows during 2014 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. The increase in estimated costs is primarily the result of various recent federal, state and local laws that regulate plugging operations and techniques. The revision in the asset retirement obligation did not have an immediate effect in the 2014 statement of operations as the increase in the revised obligation was offset by a capitalized amount, which will be depreciated over the useful lives of respective wells.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2015
Employee Benefits and Share-based Compensation [Abstract]
Compensation and Employee Benefit Plans [Text Block]	EMPLOYEE BENEFIT PLANS We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $4.9 million , $3.9 million and $3.7 million for 2015 , 2014 and 2013 , respectively. We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses and the related costs were immaterial in 2015 , 2014 and 2013 . As of December 31, 2015 and 2014 , the liability related to this benefit was $1.3 million and $1.5 million , respectively, which was included in other liabilities on the consolidated balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2015 and 2014 . We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2015 , 2014 and 2013 related to this plan were immaterial. As of December 31, 2015 and 2014 , the related liability of $0.8 million and $0.7 million , respectively, is included in other liabilities on the consolidated balance sheets. We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the consolidated balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was $0.6 million and $0.3 million as of December 31, 2015 and 2014 , respectively.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges, whether or not the required volumes are delivered. As natural gas prices continue to remain depressed, certain third-party producers under our Gas Marketing segment have begun and may continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. In 2015, we recorded an allowance for doubtful accounts of approximately $0.5 million . We have initiated several legal actions for collection against some of the third-party producers, which have resulted in no collections and some of the third-party producers shutting-in wells. The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity: Year Ending December 31, Area 2016 2017 2018 2019 2020 and Total Expiration Natural gas (MMcf) Gas Marketing segment 7,136 7,117 7,117 7,117 18,687 47,174 August 31, 2022 Utica Shale 2,745 2,737 2,737 2,737 9,811 20,767 July 22, 2023 Total 9,881 9,854 9,854 9,854 28,498 67,941 Crude oil (MBbls) Wattenberg Field 2,420 2,413 2,413 2,413 1,205 10,864 June 30, 2020 Dollar commitment (in thousands) $ 17,622 $ 17,156 $ 16,324 $ 16,324 $ 17,193 $ 84,619 Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. Class Action Regarding 2010 and 2011 Partnership Purchases In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of unit holders of 12 former limited partnerships, related to its repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and was titled Schulein v. Petroleum Development Corp . The complaint primarily alleged that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court. In October 2014, the Company and plaintiffs’ counsel reached a settlement agreement in principal, which was signed in December 2014 and was given final court approval in March 2015. Under this settlement agreement, the plaintiffs received a cash payment of $37.5 million in January 2015, of which the Company paid $31.5 million and insurers paid $6 million . In March 2015, the class action was dismissed with prejudice and all class claims were released. As of December 31, 2014, the Company accrued a liability of $37.5 million related to this litigation, which was included in other accrued expenses in the consolidated balance sheet. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2015 and 2014 , we had accrued environmental liabilities in the amount of $4.1 million and $0.8 million , respectively, included in other accrued expenses on the consolidated balance sheets. We are not aware of any environmental claims existing as of December 31, 2015 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties. In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the United States Environmental Protection Agency ("EPA"). The Information Request seeks, among other things, information related to the design, operation, and maintenance of our production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses primarily on 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. We cannot predict the outcome of this matter at this time. In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. We are in the process of responding to the advisory, but cannot predict the outcome of this matter at this time. In 2014, we experienced a loss of well control while drilling an oil and gas well in Morgan County, Ohio. The event resulted in a release of well fluids, including oil based drilling mud. We have completed the appropriate remediation to address the release. In August 2015, the EPA issued us a Notice of Intent seeking civil penalties. We and the EPA settled this matter for a civil fine of approximately $152,000 . Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment. The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2015 : Year Ending December 31, 2016 2017 2018 2019 2020 Thereafter Total (in thousands) Minimum Lease Payments $ 2,353 $ 2,166 $ 1,975 $ 1,937 $ 1,967 $ 124 $ 10,522 Operating lease expense for the years ended 2015 , 2014 and 2013 was $9.8 million , $7.0 million and $7.0 million , respectively. Employment Agreements with Executive Officers . Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company.

COMMON STOCK

COMMON STOCK	12 Months Ended
	Dec. 31, 2015
COMMON STOCK [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block]	COMMON STOCK Sale of Equity Securities In March 2015, we completed a public offering of 4,002,000 shares of our common stock, par value $0.01 per share, at a price to us of $50.73 per share. Net proceeds of the offering were $202.9 million , after deducting offering expenses and underwriting discounts, of which $40,020 is included in common shares-par value and $202.8 million is included in additional paid-in capital ("APIC") on the December 31, 2015 consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in March 2015. In August 2013 , we completed a public offering of 5,175,000 shares of our common stock, par value $0.01 per share, at a price to us of $53.37 per share. Net proceeds of the offering were approximately $275.8 million , after deducting offering expenses and underwriting discounts, of which $51,750 is included in common shares-par value and approximately $275.8 million is included in APIC on the consolidated balance sheets. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. Stock-Based Compensation Plans 2010 Long-Term Equity Compensation Plan . In June 2010 , our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to incentive or non-qualified stock options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2015 , 1,101,831 shares remain available for issuance pursuant to the 2010 Plan. The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2015 2014 2013 (in thousands) Stock-based compensation expense $ 20,068 $ 17,518 $ 12,880 Income tax benefit (7,636 ) (5,955 ) (4,697 ) Net stock-based compensation expense $ 12,432 $ 11,563 $ 8,183 Stock Appreciation Rights ("SARs") The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. In January 2015 , the Compensation Committee awarded 68,274 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: Year Ended December 31, 2015 2014 2013 Expected term of award 5.2 years 6 years 6 years Risk-free interest rate 1.4 % 2.1 % 1.0 % Expected volatility 58.0 % 65.6 % 65.5 % Weighted-average grant date fair value per share $ 22.23 $ 29.96 $ 21.96 The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. The following table presents the changes in our SARs for all periods presented: Year Ended December 31, 2015 2014 2013 Number of Weighted-Average Average Remaining Contractual (in years) Aggregate Intrinsic (in thousands) Number of Weighted-Average Aggregate Intrinsic (in thousands) Number of Weighted-Average Aggregate Intrinsic (in thousands) Outstanding beginning of year, January 1, 279,011 $ 38.77 7.8 $ 1,472 190,763 $ 33.77 $ 3,711 118,832 $ 30.80 $ 486 Awarded 68,274 39.63 — — 88,248 49.57 — 87,078 37.18 — Exercised (20,832 ) 38.05 — 473 — — — (15,147 ) 30.06 425 Outstanding at December 31, 326,453 38.99 7.3 4,697 279,011 38.77 1,472 190,763 33.77 3,711 Exercisable at December 31, 222,489 37.70 6.8 3,489 139,334 36.27 982 51,922 29.97 1,207 Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2015 , was $1.7 million . The cost is expected to be recognized over a weighted-average period of 1.4 years. Restricted Stock Awards Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date that a participant is continuously employed. In January 2015 , the Compensation Committee awarded to our executive officers a total of 80,707 time-based restricted shares that vest ratably over a three -year period ending on January 16, 2018. The following table presents the changes in non-vested time-based awards during 2015 : Shares Weighted-Average Non-vested at December 31, 2014 564,332 $ 46.02 Granted 313,639 48.88 Vested (333,167 ) 41.59 Forfeited (19,723 ) 54.29 Non-vested at December 31, 2015 525,081 50.23 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2015 2014 2013 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 17,077 $ 18,278 $ 13,640 Total intrinsic value of time-based awards non-vested 28,029 23,290 34,688 Market price per common share as of December 31, 53.38 41.27 53.22 Weighted-average grant date fair value per share 48.88 56.45 45.53 Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2015 was $16.4 million . This cost is expected to be recognized over a weighted-average period of 1.7 years. Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. In January 2015 , the Compensation Committee awarded a total of 29,398 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2017 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2015 2014 Expected term of award 3 years 3 years Risk-free interest rate 0.9 % 0.8 % Expected volatility 53.0 % 55.2 % Weighted-average grant date fair value per share $ 66.16 $ 56.87 The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. The following table presents the change in non-vested market-based awards during 2015 : Shares Weighted-Average Non-vested at December 31, 2014 83,721 $ 52.98 Granted 29,398 66.16 Vested (41,570 ) 49.04 Non-vested at December 31, 2015 71,549 63.60 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2015 2014 2013 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 4,293 $ 1,260 $ 724 Total intrinsic value of market-based awards non-vested 3,819 3,455 3,838 Market price per common share as of December 31, 53.38 41.27 53.22 Weighted-average grant date fair value per share 66.16 56.87 49.04 Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2015 was $1.9 million . This cost is expected to be recognized over a weighted-average period of 1.4 years. Treasury Share Purchases In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are reissued to service awards. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2015 , we acquired 136,168 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 127,159 shares were reissued and 9,009 shares are available for reissuance pursuant to our 2010 Plan. Shareholders’ Rights Agreement In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record in September 2007 . A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. In certain circumstances, the right entitles each holder, other than an "acquiring person" (as defined in the agreement), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire in September 2017 . Preferred stock We are authorized, pursuant to shareholder approval in 2008, to issue 50,000,000 shares of preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2015 , no preferred shares had been issued.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2015
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Earnings Per Share [Text Block]	EARNINGS PER SHARE Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, Convertible Notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. The following table presents a reconciliation of the weighted-average diluted shares outstanding: Year Ended December 31, 2015 2014 2013 (in thousands) Weighted-average common shares outstanding - basic 39,153 35,784 32,426 Dilutive effect of: Restricted stock — 279 — Convertible notes — 564 — Other equity-based awards — 51 — Weighted-average common shares and equivalents outstanding - diluted 39,153 36,678 32,426 For 2015 and 2013, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive. The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Year Ended December 31, 2015 2014 2013 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 831 8 823 Convertible notes 562 — 518 Other equity-based awards 101 26 83 Total anti-dilutive common share equivalents 1,494 34 1,424 In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the years ended December 31, 2015 and 2013, respectively, as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were included in the diluted earnings per share calculation for the year ended December 31, 2014 as the average market price during the period exceeded the conversion price.

ASSETS HELD FOR SALE, DIVESTITU

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS In October 2014 , we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. As the divestiture represents a strategic shift that will have a major effect on our operations as our organization structure will no longer have joint venture partners and we no longer have dry gas assets, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. Net assets held for sale represents the assets that are expected to be sold. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the consolidated statements of operations table presents the revenues and expenses that were reclassified from the specified consolidated statements of operations line items to discontinued operations. The following table presents consolidated statements of operations data related to our discontinued operations: Year Ended December 31, Consolidated statements of operations - discontinued operations 2014 2013 (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 24,149 $ 39,001 Sales from natural gas marketing — 2,825 Commodity price risk management income (loss), net (1,085 ) 14 Well operations, pipeline income and other 48 922 Total revenues 23,112 42,762 Costs, expenses and other Lease operating expenses 1,280 6,522 Production taxes 1,579 3,716 Transportation, gathering and processing expenses 3,536 5,283 Cost of natural gas marketing — 2,673 Impairment of crude oil and natural gas properties 433 954 Depreciation, depletion and amortization 9,128 13,894 Other 4,170 8,235 Gain on sale of properties and equipment (76,479 ) 1,700 Total costs, expenses and other (56,353 ) 42,977 Interest expense (2,222 ) (1,755 ) Interest income 194 10 Income from discontinued operations 77,437 (1,960 ) Provision for income taxes (29,263 ) 770 Income (loss) from discontinued operations, net of tax $ 48,174 $ (1,190 ) The following table presents supplemental cash flows information related to our 50% ownership interest in PDCM, which is classified as discontinued operations: Year Ended December 31, Supplemental cash flows information - discontinued operations 2014 2013 (in thousands) Cash flows from investing activities: Capital expenditures $ (17,253 ) $ (45,277 ) Significant non-cash investing items: Change in accounts payable related to purchases of properties and equipment (5,727 ) (4,738 ) Assets held for sale of $2.9 million as of December 31, 2015 and 2014 represents the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters.

TRANSACTIONS WITH AFFILIATES AN

TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	TRANSACTIONS WITH AFFILIATES PDCM and Affiliated Partnerships. Our Gas Marketing segment marketed the natural gas produced by our affiliated partnerships and, until the fourth quarter of 2014, by PDCM. Our cost of natural gas marketing includes $1.3 million in 2013 related to the marketing of natural gas on behalf of our affiliated partnerships and $23.2 million and $18.1 million in 2014 and 2013 , respectively, related to the marketing of natural gas on behalf of PDCM. Prior to October 2014, amounts due from/to affiliates included amounts billed for certain well operating and administrative services provided to PDCM. Amounts billed to PDCM for these services were $5.7 million and $14.5 million in 2014 and 2013, respectively. Our consolidated statements of operations include only our proportionate share of these billings. All amounts billed to PDCM for operating and administrative services in 2014 have been collected. Accordingly, we had no amounts due from PDCM as of December 31, 2014.

BUSINESS SEGMENTS

BUSINESS SEGMENTS	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Reporting Disclosure [Text Block]	BUSINESS SEGMENTS We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net, and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oil and natural gas properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $298.8 million , $188.5 million and $111.6 million in 2015 , 2014 and 2013 , respectively. Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing, transportation and direct general and administrative expense. Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate, general and administrative purposes, as well as assets not specifically included in our two business segments. The following tables present our segment information: 2015 2014 — 2013 (in thousands) Year Ended December 31, Segment revenues: Oil and gas exploration and production $ 584,406 $ 784,636 $ 322,878 Gas marketing 10,920 71,571 69,787 Total revenues $ 595,326 $ 856,207 $ 392,665 Segment income (loss) before income taxes: Oil and gas exploration and production $ 31,429 $ 344,149 $ 81,913 Gas marketing (797 ) (445 ) (297 ) Unallocated (137,220 ) (166,476 ) (114,579 ) Income (loss) before income taxes $ (106,588 ) $ 177,228 $ (32,963 ) Expenditures for segment long-lived assets: Oil and gas exploration and production $ 599,617 $ 623,912 $ 403,227 Unallocated 5,051 4,680 1,379 Total $ 604,668 $ 628,592 $ 404,606 As of December 31, Segment assets: Oil and gas exploration and production $ 2,294,288 $ 2,258,060 Gas marketing 4,217 6,979 Unallocated 69,164 63,227 Assets held for sale 2,874 2,874 Total assets $ 2,370,543 $ 2,331,140

SUPPLEMENTAL INFORMATION - NATU

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Information - Oil and Gas Exploration and Production Industries Disclosures [Text Block]	NATURAL GAS INFORMATION - UNAUDITED Net Proved Reserves All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGL reserves. As of December 31, 2015 , 2014 and 2013 , all of our estimates of proved reserves were based on reserve reports prepared by Ryder Scott Company, L.P. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. Proved reserves are those quantities of crude oil, natural gas and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date. The netted back price 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 ___________ * These prices are based on the index prices and are net of basin differentials, any transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity. 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 2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16% for 2015. Our actual conversion rate was 17% , resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015. Extensions, discoveries and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects are largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We have 791 gross PUD horizontal drilling locations at December 31, 2015, which is an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of prior year-end. We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments. Based on the economic conditions on December 31, 2015, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. The continued success of our increased well density tests in the Wattenberg Field in 2015 allowed for the additional increased well density of PUD locations as of December 31, 2015. Because we expect to continue to drill primarily proven Wattenberg Field locations in 2016 and as a result of additional newly-booked downspaced PUDs at December 31, 2015, our 2016 PUD conversion rate is expected to be approximately 19% . The balance of the locations are scheduled to be drilled over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. 2014 Activity . Overall, our proved reserves decreased by 16 MMBoe as of December 31, 2014 as compared to December 31, 2013. In 2014, we produced 9.3 MMBoe. At December 31, 2013, we projected a PUD conversion rate of 7% for 2014. Our actual conversion rate was 7% , resulting in 13 MMBoe of reserves booked as PUDs at December 31, 2013 being converted to proved developed reserves during 2014. As shown, we acquired minimal proved reserves in 2014. We divested a total of 40 MMBoe in 2014, primarily from the sale of our Marcellus Shale assets. Extensions, discoveries and other additions, including infill reserves, resulted in an increase of approximately 98 MMBoe in 2014, substantially all of which was added in the Wattenberg Field and primarily related to Niobrara and Codell projects. These reserve increases are primarily due to adding 78 MMBoe from new proved undeveloped reserves as a result of adjustments in well spacing, which extended the field by enabling us to book more reserves per section in the Niobrara and Codell formations. In addition approximately 16 MMBoe of previously unbooked locations were developed in the current year and 2 MMBoe due to various other factors. Approximately 2 MMBoe was added in the Utica Shale. We recorded a downward revision of our previous estimate of proved reserves of approximately 65 MMBoe. The revision was primarily related to decreases of approximately 55 MMBoe for adjustments to our development plans in the Wattenberg Field to focus on a more balanced commodity production mix and increased well density which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. In addition, 8 MMBoe of Utica Shale PUDs are no longer in our drilling plans as we directed more capital to higher-return projects in the Wattenberg Field and 2 MMBoe that were due to various other factors. Based on the economic conditions on December 31, 2014, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2014 drilling program focused on testing increased well density in the Wattenberg Field. 2013 Activity. Overall, our proved reserves increased by 73 MMBoe as of December 31, 2013 as compared to December 31, 2012. In 2013, we produced 7.4 MMBoe. At December 31, 2012, we projected a PUD conversion rate of 15% to 20% for 2013. Our actual conversion rate was 3% , resulting in 3 MMBoe of reserves booked as PUDs at December 31, 2012 being converted to proved developed reserves during 2013. As shown, we acquired 1 MMBoe of proved reserves in 2013. We divested a total of 16 MMBoe in 2013, primarily related to the sales of our Piceance Basin, NECO and shallow Upper Devonian (non-Marcellus Shale) assets. Extensions, discoveries and other additions, including infill reserves, of approximately 142 MMBoe were added in 2013, approximately 110 MMBoe, 18 MMBoe and 14 MMBoe of which were added to the Wattenberg Field, Marcellus Shale and Utica Shale, respectively. Approximately 125 MMBoe of new proved undeveloped reserves were booked, including 32 MMBoe due to adjustments in well spacing in the Wattenberg Field and Marcellus Shale. In addition, approximately 17 MMBoe of previously unbooked locations were developed in the current year. We recorded a downward revision of our previous estimate of proved reserves of approximately 46 MMBoe. The revision was primarily due to a decrease of approximately 55 MMBoe, of which approximately 32 MMBoe is due to increased well density plans in the Wattenberg Field, which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule, approximately 9 MMBoe is due to expired leases, approximately 11 MMBoe is due to our shift from vertical to horizontal drilling in the Wattenberg Field and approximately 3 MMBoe is to remove Wattenberg Field PUDs that were no longer in our core drilling area. These decreases were partially offset by various factors, including but not limited to interest adjustments, well performance and changing economics. Based on the economic conditions on December 31, 2013, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2013 drilling program focused on locations that were not included in proved undeveloped reserves in the December 31, 2012 reserve report due to increased well density testing in the Wattenberg Field. The success of this increased well density testing allowed us to add considerable PUD reserves in the 2013 reserve report. Results of Operations for Crude Oil and Natural Gas Producing Activities 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 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 Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities 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 Related to Crude Oil and Natural Gas Producing Activities 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 Net Cash Flows and Changes Therein Relating to Proved Reserves The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. 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. 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. Further, future tax deductions for capital expenditures were not affected by the impairment of crude oil and natural gas properties in 2014 and 2015 as such impairments are not tax deductible. The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

SUPPLEMENTAL INFORMATION - QUAR

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL INFORMATION - UNAUDITED Quarterly financial data for the years ended December 31, 2015 and 2014 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. See Note 1, Nature of Operations and Basis of Presentation . The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. 2015 Quarter Ended March 31 June 30 September 30 December 31 Year Ended (in thousands, except per share data) Revenues: Crude oil, natural gas and NGLs sales $ 74,109 $ 96,928 $ 104,483 $ 103,193 $ 378,713 Sales from natural gas marketing 3,233 2,523 2,580 2,584 10,920 Commodity price risk management gain (loss), net 66,662 (49,041 ) 123,549 62,013 203,183 Well operations, pipeline income and other 628 550 488 844 2,510 Total revenues 144,632 50,960 231,100 168,634 595,326 Costs, expenses and other: Lease operating expenses 16,285 12,639 13,824 14,244 56,992 Production taxes 3,893 3,837 5,476 5,237 18,443 Transportation, gathering and processing expenses 1,338 1,308 3,938 3,567 10,151 Cost of natural gas marketing 3,258 2,836 2,781 2,842 11,717 Exploration expense 285 275 252 290 1,102 Impairment of crude oil and natural gas properties 2,772 4,404 154,031 413 161,620 General and administrative expense 21,045 20,728 20,278 27,908 89,959 Depreciation, depletion and amortization 55,820 70,106 80,947 96,385 303,258 Accretion of asset retirement obligations 1,560 1,588 1,594 1,551 6,293 (Gain) loss on sale of properties and equipment (21 ) (207 ) (74 ) (83 ) (385 ) Total costs, expenses and other 106,235 117,514 283,047 152,354 659,150 Income (loss) from operations 38,397 (66,554 ) (51,947 ) 16,280 (63,824 ) Interest expense (11,725 ) (11,567 ) (12,092 ) (12,187 ) (47,571 ) Interest income 1,113 1,135 1,378 1,181 4,807 Income (loss) from continuing operations before income taxes 27,785 (76,986 ) (62,661 ) 5,274 (106,588 ) Provision for income taxes (10,723 ) 30,116 21,167 (2,252 ) 38,308 Income (loss) from continuing operations 17,062 (46,870 ) (41,494 ) 3,022 (68,280 ) Income (loss) from discontinued operations, net of tax — — — — — Net income (loss) $ 17,062 $ (46,870 ) $ (41,494 ) $ 3,022 $ (68,280 ) Earnings per share: Basic Income (loss) from continuing operations $ 0.47 $ (1.17 ) $ (1.04 ) $ 0.08 $ (1.74 ) Income (loss) from discontinued operations — — — — — Net income (loss) $ 0.47 $ (1.17 ) $ (1.04 ) $ 0.08 $ (1.74 ) Diluted Income (loss) from continuing operations $ 0.46 $ (1.17 ) $ (1.04 ) $ 0.07 $ (1.74 ) Income (loss) from discontinued operations — — — — — Net income (loss) $ 0.46 $ (1.17 ) $ (1.04 ) $ 0.07 $ (1.74 ) Weighted-average common shares outstanding: Basic 36,349 40,035 40,085 40,094 39,153 Diluted 36,981 40,035 40,085 41,264 39,153 2014 Quarter Ended March 31 June 30 September 30 December 31 Year Ended (in thousands, except per share data) Revenues: Crude oil, natural gas and NGLs sales $ 120,013 $ 131,017 $ 120,526 $ 99,857 $ 471,413 Sales from natural gas marketing 26,937 22,415 13,297 8,922 71,571 Commodity price risk management gain (loss), net (24,909 ) (52,643 ) 90,213 297,643 310,304 Well operations, pipeline income and other 616 514 520 1,269 2,919 Total revenues 122,657 101,303 224,556 407,691 856,207 Costs, expenses and other: Lease operating expenses 8,371 11,961 11,020 11,050 42,402 Production taxes 6,390 7,551 8,724 2,950 25,615 Transportation, gathering and processing expenses 1,235 818 1,208 1,331 4,592 Cost of natural gas marketing 26,870 22,428 13,347 9,370 72,015 Exploration expense 307 276 190 174 947 Impairment of crude oil and natural gas properties 952 2,019 1,962 161,914 166,847 General and administrative expense 24,529 41,713 36,328 20,989 123,559 Depreciation, depletion and amortization 42,889 49,636 49,640 50,363 192,528 Accretion of asset retirement obligations 841 840 861 873 3,415 (Gain) loss on sale of properties and equipment 579 (23 ) 21 (70 ) 507 Total costs, expenses and other 112,963 137,219 123,301 258,944 632,427 Income (loss) from operations 9,694 (35,916 ) 101,255 148,747 223,780 Interest expense (12,183 ) (12,195 ) (11,821 ) (11,643 ) (47,842 ) Interest income 187 83 39 981 1,290 Income (loss) from continuing operations before income taxes (2,302 ) (48,028 ) 89,473 138,085 177,228 Provision for income taxes 894 18,650 (35,396 ) (54,115 ) (69,967 ) Income (loss) from continuing operations (1,408 ) (29,378 ) 54,077 83,970 107,261 Income (loss) from discontinued operations, net of tax (719 ) 1,191 (80 ) 47,782 48,174 Net income (loss) $ (2,127 ) $ (28,187 ) $ 53,997 $ 131,752 $ 155,435 Earnings per share: Basic Income (loss) from continuing operations $ (0.04 ) $ (0.82 ) $ 1.51 $ 2.34 $ 3.00 Income (loss) from discontinued operations (0.02 ) 0.03 — 1.33 1.34 Net income (loss) attributable to shareholders $ (0.06 ) $ (0.79 ) $ 1.51 $ 3.67 $ 4.34 Diluted Income (loss) from continuing operations $ (0.04 ) $ (0.82 ) $ 1.47 $ 2.32 $ 2.93 Income (loss) from discontinued operations (0.02 ) 0.03 — 1.32 1.31 Net income (loss) attributable to shareholders $ (0.06 ) $ (0.79 ) $ 1.47 $ 3.64 $ 4.24 Weighted-average common shares outstanding Basic 35,690 35,762 35,834 35,847 35,784 Diluted 35,690 35,762 36,828 36,146 36,678

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Consolidation, Policy [Policy Text Block]	. As of December 31, 2015 , we had four remaining affiliated partnerships that continue to conduct crude oil and natural gas producing activities. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates, Policy [Policy Text Block]	The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves, future cash flows from crude oil and natural gas properties, valuation of derivative instruments, impairment of proved and unproved properties and valuation of deferred income tax assets
Reclassification, Policy [Policy Text Block]	• Production-related general and administrative costs totaling $7.7 million and $3.8 million for 2014 and 2013, respectively, have been reclassified from production costs to general and administrative expense; • Prepaid well costs write-offs totaling $3.3 million and $0.4 million for 2014 and 2013, respectively, have been reclassified from production costs to impairment of crude oil and natural gas properties; and • Prepaid well costs totaling $27.3 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets to properties and equipment, net; We evaluated the impact of these misclassifications and determined they were not material to the prior periods presented. Additionally, as a result of adopting the accounting standards update on the balance sheet classification of debt issuance costs and deferred taxes, the following reclassifications have been made to the prior period financial statements: • Debt issuance costs totaling $9.4 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets and are presented as a direct deduction from the carrying amount of long-term debt; and • Current deferred income tax liabilities totaling $59.2 million in the December 31, 2014 consolidated balance sheet have been reclassified to non-current pursuant to the income tax accounting standards update issued and adopted in 2015. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity.
Cash and Cash Equivalents, Policy [Policy Text Block]	We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.
Inventory, Policy [Policy Text Block]	Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our crude oil and natural gas operations.
Derivative Financial Instruments, Policy [Policy Text Block]	All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled derivatives depends on the purpose for issuing or holding the derivative. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.
Natugal Gas and Crude Oil Properties, Policy [Policy Text Block]	We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded.
Proved and Unproved Property, Impairment [Policy Text Block]	e assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of crude oil and natural gas properties.
Property, Plant and Equipment, Policy [Policy Text Block]	Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income.
Interest Capitalization, Policy [Policy Text Block]	Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset.
Assets Held For Sale, Policy [Policy Text Block]	Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations.
Production Tax Liability, Policy [Policy Text Block]	Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed and included in the statement of operations line item production taxes. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets.
Income Tax, Policy [Policy Text Block]	We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable.
Debt Issuance Costs, Policy [Policy Text Block]	Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method.
Asset Retirement Obligations, Policy [Policy Text Block]	We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations.
Treasury Shares, Policy [Policy Text Block]	We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.
Revenue Recognition, Policy [Policy Text Block]	Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. Our crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the transportation method used. We use the "net-back" method of accounting for natural gas and NGLs, as well as a portion of our crude oil production, from the Wattenberg Field and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the "gross" method of accounting for Wattenberg Field crude oil delivered through the White Cliffs pipeline and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering or processing services. Under this method, we recognize revenues based on the gross selling price. Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, RNG, suppliers and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled derivatives of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the affiliated partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured.
Accounting for Acquisitions using Purchase Accounting [Policy Text Block]	We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Stock-Based Compensation, Policy [Policy Text Block]	Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations.
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]	We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations.
Revenue Recognition, Interest [Policy Text Block]	Interest income on our note receivable is recognized over its term using the effective interest method.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards. In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when (or as) each performance obligation is satisfied. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are currently evaluating the impact these changes may have on our consolidated financial statements. In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on our consolidated financial statements.
New Accounting Pronouncement, Early Adoption [Table Text Block]	Recently Adopted Accounting Standards. In November 2014, the FASB issued an update to accounting for derivatives and hedging instruments. The update clarifies how current accounting guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the accounting update clarifies that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the update clarifies that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The assessment of the substance of the relevant terms and features should incorporate a consideration of the characteristics of the terms and features themselves, the circumstances under which the hybrid financial instrument was issued or acquired, and the potential outcomes of the hybrid financial instrument, as well as the likelihood of those potential outcomes. The accounting update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In February 2015, the FASB issued an accounting update modifying existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2015, and require either a retrospective or a modified retrospective approach to adoption. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In April 2015, the FASB issued an accounting update simplifying the presentation of debt issuance costs and requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The update did not affect the recognition and measurement guidance for debt issuance costs. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. See Note 1, Nature of Operations and Basis of Presentation, for the amounts reclassified in the December 31, 2014 consolidated balance sheet. In July 2015, the FASB issued an accounting update requiring all entities to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In September 2015, the FASB issued an accounting update requiring adjustments to provisional amounts that are identified during the measurement period of a business combination to be recognized in the reporting period in which the adjustment amounts are determined. The accounting update also requires an entity to present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current-period earnings, by line item, that would have been recorded in previous reporting periods if the adjustment to the estimated amounts had been recognized as of the acquisition date. This guidance is effective for public entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The accounting update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. In November 2015, the FASB issued an accounting update simplifying the presentation of deferred income taxes by requiring that all deferred tax liabilities and assets, along with any related valuation allowance, be classified as non-current in a classified statement of financial position. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. See Note 1, Nature of Operations and Basis of Presentation, for the amounts reclassified in the December 31, 2014 consolidated balance sheet.
Earnings Per Share, Policy [Policy Text Block]	Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, Convertible Notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

SUMMARY OF SIGNIFICANT ACCOUN27

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Property, Plant and Equipment, Estimated Useful Lives [Table Text Block]	Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. There were no impairments to other property and equipment in 2015 and 2013 , respectively. Total impairments to other property and equipment was $0.8 million in 2014 . The following table presents the estimated useful lives of our other property and equipment: Transportation and other equipment 3 - 20 years Buildings 20 - 30 years

FAIR VALUE MEASUREMENTS AND D28

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: As of December 31, 2015 2014 Significant Other Significant Total Significant Other Significant Total (in thousands) Assets: Commodity-based derivative contracts $ 174,657 $ 91,288 $ 265,945 $ 237,939 $ 62,356 $ 300,295 Basis protection derivative contracts 101 — 101 19 — 19 Total assets 174,758 91,288 266,046 237,958 62,356 300,314 Liabilities: Commodity-based derivative contracts 738 — 738 742 — 742 Basis protection derivative contracts 1,552 — 1,552 25 — 25 Total liabilities 2,290 — 2,290 767 — 767 Net asset $ 172,468 $ 91,288 $ 263,756 $ 237,191 $ 62,356 $ 299,547
Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block]	The following table presents a reconciliation of our Level 3 assets measured at fair value: 2015 2014 2013 (in thousands) Fair value, net asset beginning of period $ 62,356 $ 1,111 $ 13,610 Changes in fair value included in statement of operations line item: Commodity price risk management gain (loss), net 65,018 62,003 (1,748 ) Sales from natural gas marketing 146 (22 ) 13 Settlements included in statement of operations line items: Commodity price risk management gain (loss), net (36,169 ) (737 ) (6,361 ) Sales from natural gas marketing (63 ) 1 (37 ) Loss from discontinued operations, net of tax — — (4,366 ) Fair value, net asset end of period $ 91,288 $ 62,356 $ 1,111 Net change in fair value of unsettled derivatives included in statement of operations line item: Commodity price risk management gain (loss), net $ 43,540 $ 15,632 $ (2,731 ) Sales from natural gas marketing — 3 4 Total $ 43,540 $ 15,635 $ (2,727 )

DERIVATIVE FINANCIAL INSTRUME29

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2015 and 2014 : Derivative instruments: Balance sheet line item 2015 2014 (in thousands) Derivative assets: Current Commodity contracts Related to crude oil and natural gas sales Fair value of derivatives $ 221,161 $ 186,886 Related to natural gas marketing Fair value of derivatives 441 590 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 57 19 221,659 187,495 Non-current Commodity contracts Related to crude oil and natural gas sales Fair value of derivatives 44,292 112,599 Related to natural gas marketing Fair value of derivatives 51 220 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 44 — 44,387 112,819 Total derivative assets $ 266,046 $ 300,314 Derivative liabilities: Current Commodity contracts Related to natural gas marketing Fair value of derivatives $ 417 $ 545 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 1,178 25 1,595 570 Non-current Commodity contracts Related to crude oil and natural gas sales Fair value of derivatives 275 — Related to natural gas marketing Fair value of derivatives 46 197 Basis protection contracts Related to crude oil and natural gas sales Fair value of derivatives 374 — 695 197 Total derivative liabilities $ 2,290 $ 767 The following table presents the impact of our derivative instruments on our consolidated statements of operations: Year Ended December 31, Consolidated statement of operations line item 2015 2014 2013 (in thousands) Commodity price risk management gain (loss), net Net settlements $ 238,935 $ (837 ) $ 11,177 Net change in fair value of unsettled derivatives (35,752 ) 311,141 (35,096 ) Total commodity price risk management gain (loss), net $ 203,183 $ 310,304 $ (23,919 ) Sales from natural gas marketing Net settlements $ 778 $ (208 ) $ 446 Net change in fair value of unsettled derivatives (318 ) 364 429 Total sales from natural gas marketing $ 460 $ 156 $ 875 Cost of natural gas marketing Net settlements $ (745 ) $ 346 $ (257 ) Net change in fair value of unsettled derivatives 279 (451 ) (412 ) Total cost of natural gas marketing $ (466 ) $ (105 ) $ (669 ) All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of December 31, 2015 Derivative instruments, recorded in consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 266,046 $ (1,921 ) $ 264,125 Liability derivatives: Derivative instruments, at fair value $ 2,290 $ (1,921 ) $ 369 As of December 31, 2014 Derivative instruments, recorded in consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 300,314 $ (29 ) $ 300,285 Liability derivatives: Derivative instruments, at fair value $ 767 $ (29 ) $ 738

CONCENTRATION OF RISK Accounts

CONCENTRATION OF RISK Accounts Receivable, net of Allowance for Doubtful Accounts (Tables)	12 Months Ended
	Dec. 31, 2015
Concentration Risks, Types, No Concentration Percentage [Abstract]
Accounts Receivable [Table Text Block]	Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: As of December 31, 2015 2014 (in thousands) Crude oil, natural gas and NGLs sales $ 41,873 $ 49,531 Joint interest billings 35,017 52,841 Derivative counterparties 24,437 12,582 Insurance reimbursement 879 11,212 Other 4,077 5,524 Allowance for doubtful accounts (2,009 ) (486 ) Accounts receivable, net $ 104,274 $ 131,204
Individual Customers Constituting 10% or more of Total Revenue [Table Text Block]	Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: Year Ended December 31, Customer 2015 2014 2013 Concord Energy 23.2 % 18.3 % — % Suncor Energy Marketing, Inc. 14.3 % 19.7 % 35.9 % Shell Trading Company 13.8 % — % — % DCP Midstream, LP 13.2 % 15.1 % 13.9 % Teppco Crude Oil, LLC — % 12.9 % 8.0 %
Fair Value, Concentration of Risk [Table Text Block]	The following table presents the counterparties that expose us to credit risk as of December 31, 2015 , with regard to our derivative assets: Fair Value of Counterparty Name As of December 31, 2015 (in thousands) Canadian Imperial Bank of Commerce (1) $ 78,102 JP Morgan Chase Bank, N.A (1) 71,012 Bank of Nova Scotia (1) 49,758 Wells Fargo Bank, N.A. (1) 32,474 NATIXIS (1) 29,754 Other lenders in our revolving credit facility 4,856 Other (2) 90 Total $ 266,046 ____________ (1) Major lender in our revolving credit facility. See Note 8, Long-Term Debt. (2) Represents one counterparty.
Notes Receivable [Table Text Block]	The following table presents information regarding our note receivable outstanding as of December 31, 2015 : Amount (in thousands) Note receivable: Principal outstanding, December 31, 2014 $ 39,707 Paid-in-kind interest 3,362 Principal outstanding, December 31, 2015 $ 43,069

PROPERTIES AND EQUIPMENT Proper

PROPERTIES AND EQUIPMENT Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	The following table presents the components of properties and equipment, net of accumulated DD&A: As of December 31, 2015 2014 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 2,881,189 $ 2,267,165 Unproved 60,498 188,206 Total crude oil and natural gas properties 2,941,687 2,455,371 Equipment and other 30,098 29,562 Land and buildings 9,015 9,015 Construction in progress 113,115 165,205 Properties and equipment, at cost 3,093,915 2,659,153 Accumulated DD&A (1,156,237 ) (831,699 ) Properties and equipment, net $ 1,937,678 $ 1,827,454
Impairment of natural gas and crude oil properties [Table Text Block]	The following table presents impairment charges recorded for crude oil and natural gas properties: Year Ended December 31, 2015 2014 2013 (in thousands) Continuing operations: Impairment of proved and unproved properties $ 154,608 $ 161,604 $ 49,631 Amortization of individually insignificant unproved properties 7,012 4,465 3,242 Other — 778 — Total continuing operations 161,620 166,847 52,873 Discontinued operations: Impairment of proved and unproved properties — 433 566 Amortization of individually insignificant unproved properties — — 363 Total discontinued operations — 433 929 Total impairment of crude oil and natural gas properties $ 161,620 $ 167,280 $ 53,802

INCOME TAXES Income Taxes (Tabl

INCOME TAXES Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The table below presents the components of our provision for income taxes from continuing operations for the years presented: Year Ended December 31, 2015 2014 2013 (in thousands) Current: Federal $ (2,944 ) $ (1,514 ) $ 1,355 State (163 ) 966 199 Total current income taxes (3,107 ) (548 ) 1,554 Deferred: Federal 37,352 (60,698 ) 8,238 State 4,063 (8,721 ) 2,060 Total deferred income taxes 41,415 (69,419 ) 10,298 Income tax benefit (expense) from continuing operations $ 38,308 $ (69,967 ) $ 11,852
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: Year Ended December, 31, 2015 2014 2013 Statutory tax rate 35.0 % 35.0 % 35.0 % State income tax, net 2.4 2.8 4.0 Percentage depletion 0.3 (0.3 ) 2.2 Non-deductible compensation (1.2 ) 0.7 (4.2 ) Other (0.6 ) 1.3 (1.0 ) Effective tax rate 35.9 % 39.5 % 36.0 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2015 and 2014 are presented below: As of December 31, 2015 2014 (in thousands) Deferred tax assets: Deferred compensation $ 13,104 $ 10,459 Asset retirement obligations 34,101 28,051 State NOL and tax credit carryforwards, net 3,376 3,761 Alternative minimum tax - credit carryforward 2,812 2,906 Settlement of class action litigation — 12,259 Other 3,412 3,144 Deferred tax assets 56,805 60,580 Deferred tax liabilities: Properties and equipment 99,191 130,155 Net change in fair value of unsettled derivatives 100,369 113,007 Convertible debt 697 2,285 Total gross deferred tax liabilities 200,257 245,447 Net deferred tax liability $ 143,452 $ 184,867

LONG-TERM DEBT LONG-TERM DEBT (

LONG-TERM DEBT LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt consists of the following: As of December 31, 2015 2014 (in thousands) Senior notes: 3.25% Convertible senior notes due 2016: Principal amount $ 115,000 $ 115,000 Unamortized discount (1,852 ) (6,077 ) Unamortized debt issuance costs (208 ) (765 ) 3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs 112,940 108,158 7.75% Senior notes due 2022: Principal amount 500,000 500,000 Unamortized debt issuance costs (7,563 ) (8,683 ) 7.75% Senior notes due 2022, net of unamortized debt issuance costs 492,437 491,317 Total senior notes 605,377 599,475 Revolving credit facility 37,000 56,000 Total debt, net of discount and unamortized debt issuance costs 642,377 655,475 Less current portion of long-term debt 112,940 — Long-term debt $ 529,437 $ 655,475

CAPITAL LEASES (Tables)

CAPITAL LEASES (Tables)	12 Months Ended
	Dec. 31, 2015
Capital Leases [Abstract]
Schedule of Capital Leased Assets [Table Text Block]	The following table presents leased vehicles under capital leases as of December 31, 2015 : Amount (in thousands) Vehicles $ 1,601 Accumulated depreciation (211 ) $ 1,390
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: For the Twelve Months Ending December 31, Amount (in thousands) 2016 $ 492 2017 492 2018 681 1,665 Less executory cost (70 ) Less amount representing interest (202 ) Present value of minimum lease payments $ 1,393 Short-term capital lease obligations $ 357 Long-term capital lease obligations 1,036 $ 1,393

ASSET RETIREMENT OBLIGATIONS As

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: 2015 2014 (in thousands) Balance at beginning of period, January 1, 2015 $ 73,855 $ 41,030 Revisions in estimated cash flows 11,658 31,945 Obligations incurred with development activities 2,373 1,170 Accretion expense 6,293 3,455 Obligations discharged with asset retirements (4,687 ) (3,745 ) Balance end of period, December 31, 2015 89,492 73,855 Less current portion (5,460 ) (1,863 ) Long-term portion $ 84,032 $ 71,992

COMMITMENTS AND CONTINGENCIES C

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment [Table Text Block]	The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity: Year Ending December 31, Area 2016 2017 2018 2019 2020 and Total Expiration Natural gas (MMcf) Gas Marketing segment 7,136 7,117 7,117 7,117 18,687 47,174 August 31, 2022 Utica Shale 2,745 2,737 2,737 2,737 9,811 20,767 July 22, 2023 Total 9,881 9,854 9,854 9,854 28,498 67,941 Crude oil (MBbls) Wattenberg Field 2,420 2,413 2,413 2,413 1,205 10,864 June 30, 2020 Dollar commitment (in thousands) $ 17,622 $ 17,156 $ 16,324 $ 16,324 $ 17,193 $ 84,619
Schedule of Minimum Future Lease Payments under the Non-cancelable Operating Leases [Table Text Block]	The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2015 : Year Ending December 31, 2016 2017 2018 2019 2020 Thereafter Total (in thousands) Minimum Lease Payments $ 2,353 $ 2,166 $ 1,975 $ 1,937 $ 1,967 $ 124 $ 10,522

COMMON STOCK Common Stock (Tabl

COMMON STOCK Common Stock (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]	The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2015 2014 2013 (in thousands) Stock-based compensation expense $ 20,068 $ 17,518 $ 12,880 Income tax benefit (7,636 ) (5,955 ) (4,697 ) Net stock-based compensation expense $ 12,432 $ 11,563 $ 8,183
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	In January 2015 , the Compensation Committee awarded 68,274 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: Year Ended December 31, 2015 2014 2013 Expected term of award 5.2 years 6 years 6 years Risk-free interest rate 1.4 % 2.1 % 1.0 % Expected volatility 58.0 % 65.6 % 65.5 % Weighted-average grant date fair value per share $ 22.23 $ 29.96 $ 21.96
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity [Table Text Block]	The following table presents the changes in our SARs for all periods presented: Year Ended December 31, 2015 2014 2013 Number of Weighted-Average Average Remaining Contractual (in years) Aggregate Intrinsic (in thousands) Number of Weighted-Average Aggregate Intrinsic (in thousands) Number of Weighted-Average Aggregate Intrinsic (in thousands) Outstanding beginning of year, January 1, 279,011 $ 38.77 7.8 $ 1,472 190,763 $ 33.77 $ 3,711 118,832 $ 30.80 $ 486 Awarded 68,274 39.63 — — 88,248 49.57 — 87,078 37.18 — Exercised (20,832 ) 38.05 — 473 — — — (15,147 ) 30.06 425 Outstanding at December 31, 326,453 38.99 7.3 4,697 279,011 38.77 1,472 190,763 33.77 3,711 Exercisable at December 31, 222,489 37.70 6.8 3,489 139,334 36.27 982 51,922 29.97 1,207
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]	The following table presents the changes in non-vested time-based awards during 2015 : Shares Weighted-Average Non-vested at December 31, 2014 564,332 $ 46.02 Granted 313,639 48.88 Vested (333,167 ) 41.59 Forfeited (19,723 ) 54.29 Non-vested at December 31, 2015 525,081 50.23 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2015 2014 2013 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 17,077 $ 18,278 $ 13,640 Total intrinsic value of time-based awards non-vested 28,029 23,290 34,688 Market price per common share as of December 31, 53.38 41.27 53.22 Weighted-average grant date fair value per share 48.88 56.45 45.53
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block]	The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2015 2014 Expected term of award 3 years 3 years Risk-free interest rate 0.9 % 0.8 % Expected volatility 53.0 % 55.2 % Weighted-average grant date fair value per share $ 66.16 $ 56.87
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	The following table presents the change in non-vested market-based awards during 2015 : Shares Weighted-Average Non-vested at December 31, 2014 83,721 $ 52.98 Granted 29,398 66.16 Vested (41,570 ) 49.04 Non-vested at December 31, 2015 71,549 63.60 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2015 2014 2013 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 4,293 $ 1,260 $ 724 Total intrinsic value of market-based awards non-vested 3,819 3,455 3,838 Market price per common share as of December 31, 53.38 41.27 53.22 Weighted-average grant date fair value per share 66.16 56.87 49.04

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation [Table Text Block]	The following table presents a reconciliation of the weighted-average diluted shares outstanding: Year Ended December 31, 2015 2014 2013 (in thousands) Weighted-average common shares outstanding - basic 39,153 35,784 32,426 Dilutive effect of: Restricted stock — 279 — Convertible notes — 564 — Other equity-based awards — 51 — Weighted-average common shares and equivalents outstanding - diluted 39,153 36,678 32,426
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Year Ended December 31, 2015 2014 2013 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 831 8 823 Convertible notes 562 — 518 Other equity-based awards 101 26 83 Total anti-dilutive common share equivalents 1,494 34 1,424

ASSETS HELD FOR SALE, DIVESTI39

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Assets Held for Sale, Divestitures and Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]	The following table presents consolidated statements of operations data related to our discontinued operations: Year Ended December 31, Consolidated statements of operations - discontinued operations 2014 2013 (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 24,149 $ 39,001 Sales from natural gas marketing — 2,825 Commodity price risk management income (loss), net (1,085 ) 14 Well operations, pipeline income and other 48 922 Total revenues 23,112 42,762 Costs, expenses and other Lease operating expenses 1,280 6,522 Production taxes 1,579 3,716 Transportation, gathering and processing expenses 3,536 5,283 Cost of natural gas marketing — 2,673 Impairment of crude oil and natural gas properties 433 954 Depreciation, depletion and amortization 9,128 13,894 Other 4,170 8,235 Gain on sale of properties and equipment (76,479 ) 1,700 Total costs, expenses and other (56,353 ) 42,977 Interest expense (2,222 ) (1,755 ) Interest income 194 10 Income from discontinued operations 77,437 (1,960 ) Provision for income taxes (29,263 ) 770 Income (loss) from discontinued operations, net of tax $ 48,174 $ (1,190 )

BUSINESS SEGMENTS Business Segm

BUSINESS SEGMENTS Business Segments (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information [Table Text Block]	The following tables present our segment information: 2015 2014 — 2013 (in thousands) Year Ended December 31, Segment revenues: Oil and gas exploration and production $ 584,406 $ 784,636 $ 322,878 Gas marketing 10,920 71,571 69,787 Total revenues $ 595,326 $ 856,207 $ 392,665 Segment income (loss) before income taxes: Oil and gas exploration and production $ 31,429 $ 344,149 $ 81,913 Gas marketing (797 ) (445 ) (297 ) Unallocated (137,220 ) (166,476 ) (114,579 ) Income (loss) before income taxes $ (106,588 ) $ 177,228 $ (32,963 ) Expenditures for segment long-lived assets: Oil and gas exploration and production $ 599,617 $ 623,912 $ 403,227 Unallocated 5,051 4,680 1,379 Total $ 604,668 $ 628,592 $ 404,606 As of December 31, Segment assets: Oil and gas exploration and production $ 2,294,288 $ 2,258,060 Gas marketing 4,217 6,979 Unallocated 69,164 63,227 Assets held for sale 2,874 2,874 Total assets $ 2,370,543 $ 2,331,140

SUPPLEMENTAL INFORMATION - NA41

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 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.

NATURE OF OPERATIONS AND BASI42

NATURE OF OPERATIONS AND BASIS OF PRESENTATION Additional Information (Details)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Oil and gas producing wells, gross	3,000
Number of Operating Segments	2

NATURE OF OPERATIONS AND BASI43

NATURE OF OPERATIONS AND BASIS OF PRESENTATION Reclassifications (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Misclassifications
Reclassifications:
Reclassification of production costs to general and administrative	$ 7.7	$ 3.8
Reclassification of prepaid well costs to impairment	3.3	$ 0.4
Reclassification of prepaid well costs to PP&E	27.3
Adoption of new accounting standards update
Reclassifications:
Debt issuance costs reclassified to debt	9.4
Current deferred income tax reclassified to long term	$ 59.2

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Detail (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Significant Accounting Plicies [Line Items]
Certificates of Deposit and Cash	$ 0.7	$ 0.7
Inventory, Net	0.6	0.8
White Cliffs pipeline line fill crude oil inventory	1.1
Impairment of other property and equipment	0	0.8
Non-Oil and gas Depreciation, Depletion and Amortization	4.5	4.1	$ 4
Capitalized Interest	5.1	3.5	$ 1.7
Production Tax Liability	19	26.4
Debt Issuance Cost	11.4	13.7
7.75% Senior Notes [Member]
Significant Accounting Plicies [Line Items]
Debt Issuance Cost	$ 7.6	8.7
Debt Instrument, Interest Rate, Stated Percentage	7.75%
Revolving Credit Facility [Member]
Significant Accounting Plicies [Line Items]
Debt Issuance Cost	$ 3.6	4.3
3.25% Convertible Note [Member]
Significant Accounting Plicies [Line Items]
Debt Issuance Cost	$ 0.2	$ 0.7

FAIR VALUE MEASUREMENTS AND D45

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Based Derivative Assets	$ 174,657	$ 237,939
Basis Protection Derivative Assets	101	19
Assets, Fair Value Disclosure	174,758	237,958
Commodity Based Derivative Liabilities	738	742
Basis Protection Derivative Liabilities	1,552	25
Liabilities, Fair Value Disclosure	2,290	767
Net Asset Fair Value	172,468	237,191
Fair Value | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Based Derivative Assets	91,288	62,356
Basis Protection Derivative Assets	0	0
Assets, Fair Value Disclosure	91,288	62,356
Commodity Based Derivative Liabilities	0	0
Basis Protection Derivative Liabilities	0	0
Liabilities, Fair Value Disclosure	0	0
Net Asset Fair Value	91,288	62,356
Fair Value | Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Based Derivative Assets	265,945	300,295
Basis Protection Derivative Assets	101	19
Assets, Fair Value Disclosure	266,046	300,314
Commodity Based Derivative Liabilities	738	742
Basis Protection Derivative Liabilities	1,552	25
Liabilities, Fair Value Disclosure	2,290	767
Net Asset Fair Value	$ 263,756	$ 299,547
3.25% Convertible Senior Notes due 2016 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
3.25% convertible senior notes fair value	$ 150,200
3.25% convertible senior notes fair value as a percentage of par	130.60%
7.75% Senior Notes [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.75%
7.75% senior notes fair value	$ 485,000
7.75% senior notes fair value as percentage of par	97.00%

FAIR VALUE MEASUREMENTS AND D46

FAIR VALUE MEASUREMENTS AND DISCLOSURES Reconciliation of Level 3 Fair Value Measurements (Details) - Derivative Financial Instrument Net Assets [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value	$ 91,288	$ 62,356	$ 1,111	$ 13,610
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	43,540	15,635	(2,727)
Commodity Price Risk Management, net
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings	65,018	62,003	(1,748)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	(36,169)	(737)	(6,361)
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	43,540	15,632	(2,731)
Sales From Natural Gas Marketing
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings	146	(22)	13
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	(63)	1	(37)
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	0	3	4
Net Assets Related to Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	$ 0	$ 0	$ (4,366)

DERIVATIVE FINANCIAL INSTRUME47

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 2,290	$ 767
Derivative Asset, Fair Value, Gross Asset	266,046	300,314
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	221,659	187,495
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	44,387	112,819
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,595	570
Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	695	197
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	221,161	186,886
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	44,292	112,599
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	275	0
Commodity Contracts Related to Natural Gas Marketing [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	441	590
Commodity Contracts Related to Natural Gas Marketing [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	51	220
Commodity Contracts Related to Natural Gas Marketing [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	417	545
Commodity Contracts Related to Natural Gas Marketing [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	46	197
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	57	19
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	44	0
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	1,178	25
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	$ 374	$ 0

DERIVATIVE FINANCIAL INSTRUME48

DERIVATIVE FINANCIAL INSTRUMENTS Impact of Derivative Instruments on Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commodity Price Risk Management, net
Derivative [Line Items]
Net settlements	$ 238,935	$ (837)	$ 11,177
Net change in fair value of unsettled derivatives	(35,752)	311,141	(35,096)
Total Derivative Gain (Loss)	203,183	310,304	(23,919)
Sales From Natural Gas Marketing
Derivative [Line Items]
Net settlements	778	(208)	446
Net change in fair value of unsettled derivatives	(318)	364	429
Total Derivative Gain (Loss)	460	156	875
Cost of Natural Gas Marketing
Derivative [Line Items]
Net settlements	(745)	346	(257)
Net change in fair value of unsettled derivatives	279	(451)	(412)
Total Derivative Gain (Loss)	$ (466)	$ (105)	$ (669)

DERIVATIVE FINANCIAL INSTRUME49

DERIVATIVE FINANCIAL INSTRUMENTS Effect of Master Netting Agreements (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 266,046	$ 300,314
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(1,921)	(29)
Derivative Asset	264,125	300,285
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	2,290	767
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(1,921)	(29)
Derivative Liability	$ 369	$ 738

DERIVATIVE FINANCIAL INSTRUME50

DERIVATIVE FINANCIAL INSTRUMENTS Additional Information (Details) MMBTU in Thousands	Dec. 31, 2015MMBTUMBbls
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Portion of Anticipated Natural Gas Production Hedged (MMBtu) | MMBTU	77,320
Portion of Future Oil and Gas Production Being Hedged (MBbls) | MBbls	5,580

CONCENTRATION OF RISK Account51

CONCENTRATION OF RISK Accounts Receivable, Net of Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk [Line Items]
Allowance for Doubtful Accounts Receivable, Current	$ (2,009)	$ (486)
Accounts Receivable, Net, Current	104,274	131,204
Natural gas, NGLs and crude oil sales
Concentration Risk [Line Items]
Accounts Receivable, Gross	41,873	49,531
Joint interest billing
Concentration Risk [Line Items]
Accounts Receivable, Gross	35,017	52,841
Derivative Counterparties
Concentration Risk [Line Items]
Accounts Receivable, Gross	24,437	12,582
Insurance Reimbursement
Concentration Risk [Line Items]
Accounts Receivable, Gross	879	11,212
Other Accounts Receivable
Concentration Risk [Line Items]
Accounts Receivable, Gross	$ 4,077	$ 5,524

CONCENTRATION OF RISK Customer

CONCENTRATION OF RISK Customer Constituting 10% or more of Total Revenue (Details)	12 Months Ended
	Dec. 31, 2015Rate	Dec. 31, 2014Rate	Dec. 31, 2013Rate
Suncor Energy Marketing, Inc.
Concentration Risk [Line Items]
Percentage of Revenue	14.30%	19.70%	35.90%
Percentage of Accounts Receivable Balance at Year-End		11.10%
Concord Energy
Concentration Risk [Line Items]
Percentage of Revenue	23.20%	18.30%	0.00%
Percentage of Accounts Receivable Balance at Year-End	11.30%	10.30%
Shell Trading Company
Concentration Risk [Line Items]
Percentage of Revenue	13.80%	0.00%	0.00%
DCP Midstream, LP
Concentration Risk [Line Items]
Percentage of Revenue	13.20%	15.10%	13.90%
Teppco Crude Oil
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	12.90%	8.00%

CONCENTRATION OF RISK Derivativ

CONCENTRATION OF RISK Derivative Counterparties (Details)	Dec. 31, 2015USD ($)
Concentration Risk [Line Items]
Fair Value of Derivative Assets	$ 266,046,000
Number of derivative counterparties	1
Canadian Imperial Bank of Commerce
Concentration Risk [Line Items]
Fair Value of Derivative Assets	78,102,000
JPMorgan Chase Bank [Member]
Concentration Risk [Line Items]
Fair Value of Derivative Assets	71,012,000
Natixis
Concentration Risk [Line Items]
Fair Value of Derivative Assets	29,754,000
Wells Fargo Bank
Concentration Risk [Line Items]
Fair Value of Derivative Assets	32,474,000
Bank of Nova Scotia
Concentration Risk [Line Items]
Fair Value of Derivative Assets	49,758,000
Other Lenders in Our Credit Facility
Concentration Risk [Line Items]
Fair Value of Derivative Assets	4,856,000
Various
Concentration Risk [Line Items]
Fair Value of Derivative Assets	$ 90,000	[1]
[1]	Represents one counterparty.

CONCENTRATION OF RISK Notes Rec

CONCENTRATION OF RISK Notes Receivable (Details) - Notes Receivable [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Oct. 14, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Note Receivable - Principal Outstanding	$ 43,069	$ 39,707	$ 39,000
Paid-in-Kind Interest	3,362	700
Note receivable - interest income	$ 4,500	$ 900

PROPERTIES AND EQUIPMENT Prop55

PROPERTIES AND EQUIPMENT Properties and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Proved Natural Gas and Crude Oil Properties	$ 2,881,189	$ 2,267,165
Unproved Natural Gas and Crude Oil Properties	60,498	188,206
Total Natural Gas and Crude Oil Properties	2,941,687	2,455,371
Transportation and Other Equipment	30,098	29,562
Land and Buildings	9,015	9,015
Construction in Progress	113,115	165,205
Property and Equipment, at cost	3,093,915	2,659,153
Accumulated Depreciation, Depletion and Amortization	(1,156,237)	(831,699)
Property and Equipment, Net	$ 1,937,678	$ 1,827,454

PROPERTIES AND EQUIPMENT Impair

PROPERTIES AND EQUIPMENT Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Continuing Operations:
Impairment of proved and unproved properties									$ 154,608	$ 161,604	$ 49,631
Amortization of Individually Insignificant Unproved Properties									7,012	4,465	3,242
Other									0	778	0
Results of Operations, Impairment of Oil and Gas Properties	$ 413	$ 154,031	$ 4,404	$ 2,772	$ 161,914	$ 1,962	$ 2,019	$ 952	161,620	166,847	52,873
Discontinued operations:
Impairment of individually significant unproved properties from discontinued operations									0	433	566
Amortization of Individually Insignificant Unproved Properties, discontinued operations									0	0	363
Total discontinued operations									0	433	929
Total impairment of natural gas and crude oil properties									161,620	167,280	53,802
Capitalized Well Costs
Continuing Operations:
Impairment of proved and unproved properties									24,700
Fair Value, excluding estimated salvage value	$ 27,900								27,900
Lease Acquisition Costs
Continuing Operations:
Impairment of proved and unproved properties									150,300
Unproved Properties
Continuing Operations:
Impairment of proved and unproved properties									$ 125,600	45,700
Proved and unproved properties
Continuing Operations:
Impairment of proved and unproved properties										158,300
Proved Properties
Continuing Operations:
Impairment of proved and unproved properties										$ 112,600	$ 48,800

INCOME TAXES Provision for Inco

INCOME TAXES Provision for Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current Federal Tax Benefit (Expense)									$ (2,944)	$ (1,514)	$ 1,355
Current State and Local Tax Benefit (Expense)									(163)	966	199
Current Income Tax Benefit (Expense)									(3,107)	(548)	1,554
Deferred Federal Income Tax Benefit (Expense)									37,352	(60,698)	8,238
Deferred State and Local Income Tax Benefit (Expense)									4,063	(8,721)	2,060
Deferred Income Tax Benefit (Expense)									41,415	(69,419)	10,298
Provision for income taxes	$ (2,252)	$ 21,167	$ 30,116	$ (10,723)	$ (54,115)	$ (35,396)	$ 18,650	$ 894	$ 38,308	$ (69,967)	$ 11,852

INCOME TAXES Reconciliation of

INCOME TAXES Reconciliation of Statutory Rate to Effective Rate (Details)	12 Months Ended
	Dec. 31, 2015Rate	Dec. 31, 2014Rate	Dec. 31, 2013Rate
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%
State income tax, net	2.40%	2.80%	4.00%
Percentage depletion	0.30%	(0.30%)	2.20%
Non-deductible compensation	(1.20%)	0.70%	(4.20%)
Other	(0.60%)	1.30%	(1.00%)
Effective tax rate	35.90%	39.50%	36.00%

INCOME TAXES Tax Effects of Tem

INCOME TAXES Tax Effects of Temporary differences that Give Rise to Significant Portions of the Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Components of Deferred Tax Assets [Abstract]
Deferred compensation	$ 13,104	$ 10,459
Asset retirement obligations	34,101	28,051
State NOL and tax credit carryforwards, net	3,376	3,761
Alternative minimum tax - credit carryforward	2,812	2,906
Settlement of class action litigation	0	12,259
Other	3,412	3,144
Deferred tax assets	56,805	60,580
Components of Deferred Tax Liabilities [Abstract]
properties and equipment	99,191	130,155
Net change in fair value of unsettled derivatives	100,369	113,007
Convertible debt	697	2,285
Total gross deferred tax liabilities	200,257	245,447
Net deferred tax liability	$ 143,452	$ 184,867

INCOME TAXES Unrecognized Tax B

INCOME TAXES Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Unrecognized Tax Benefits:
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 0.1	$ 0

INCOME TAXES Additional Informa

INCOME TAXES Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards:
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 0.1	$ 0
State NOL Carryforwards
Operating Loss Carryforwards:
State NOL carryforwards	$ 74.3
Year Carryforwards Expire	Dec. 31, 2030
State Credit Carryforwards
Operating Loss Carryforwards:
State credit carryforwards	$ 1.6
Year Carryforwards Expire	Dec. 31, 2022

LONG-TERM DEBT SCHEDULE OF LONG

LONG-TERM DEBT SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total senior notes	$ 605,377	$ 599,475
Total debt, net of discount and unamortized debt issuance costs	642,377	655,475
Less current portion of long-term debt	112,940	0
Long-term debt	529,437	655,475
Convertible Debt
Debt Instrument [Line Items]
Principal amount	115,000	115,000
Unamortized Discount	1,852	6,077
Unamortized Debt Issuance Costs	(208)	(765)
3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs	112,940	108,158
7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs	(7,563)	(8,683)
Principal amount	(500,000)	(500,000)
7.75% Senior notes due 2022, net of unamortized debt issuance costs	492,437	491,317
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility	37,000	$ 56,000
Convertible Debt
Debt Instrument [Line Items]
Principal amount	$ 150,200

LONG-TERM DEBT ADDITIONAL INFOR

LONG-TERM DEBT ADDITIONAL INFORMATION (Details)	Oct. 15, 2022	May. 21, 2020	May. 15, 2016	Nov. 15, 2015	Oct. 03, 2012USD ($)	Nov. 15, 2010USD ($)$ / shares	Nov. 05, 2010	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)Rate	Dec. 31, 2014USD ($)Rate	Dec. 31, 2013USD ($)
Debt Instrument [Line Items]
Debt Issuance Costs ($)									$ 974,000	$ 88,000	$ 2,352,000
3.25% Convertible Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Issuance Date						Nov. 15, 2010
Debt Instrument, Maturity Date			May 15, 2016
Debt Instrument, Interest Rate, Stated Percentage | Rate									3.25%
Debt Instrument, Call Date, Earliest				Nov. 15, 2015
Convertible Senior Note, Shares Issued Upon Conversion									23.5849
Convertible Note Principal Amount						$ 1,000
3.25% Convertible Note, Conversion Price | $ / shares						$ 42.40
3.25% Convertible Debt, Liability Component ($)						$ 94,300,000
3.25% Convertible Debt, Equity Component ($)						$ 20,700,000
3.25% Convertible Debt, Remaining Discount Amortization Period									5 months
Debt Instrument, Interest Rate During Period | Rate									7.40%
Convertible Debt, Interest Expense ($)									$ 3,700,000	3,700,000	3,700,000
Convertible Debt, Amortization of Debt Discount ($)									$ 4,200,000	$ 3,900,000	$ 3,700,000
Debt Instrument, Convertible, If-converted Value in Excess of Principal								$ 29,800,000
7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Issuance Date					Oct. 3, 2012
Debt Instrument, Maturity Date	Oct. 15, 2022
Debt Instrument, Interest Rate, Stated Percentage | Rate									7.75%
Debt Issuance Costs ($)					$ 11,000,000
Debt Instrument, Call Date, Latest					Oct. 15, 2017
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Initiation Date							Nov. 5, 2010
Line of Credit Facility, Current Borrowing Capacity ($)									$ 450,000,000
Debt agreement Amendment date								Sep. 30, 2015
Line of Credit Facility, Maximum Borrowing Capacity ($)									1,000,000,000
Line of Credit Facility, Expiration Date		May 21, 2020
Line of Credit Facility, Remaining Borrowing Capacity									$ 401,300,000
Credit Facility - Restrictive Covenants									The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the Convertible Notes. Among other things, the restriction on redemption of the Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility must exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million.
Credit Facility - Covenant Description									The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00.
Line of Credit Facility, Increase (Decrease), Net									$ 250,000,000
RNG Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount ($)									$ 11,700,000
First Payment [Member] | 3.25% Convertible Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment									May 15
First Payment [Member] | 7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment									April 15
Second Payment [Member] | 3.25% Convertible Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment									November 15
Second Payment [Member] | 7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment									October 15
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate | Rate									2.60%	3.80%
Maximum Borrowing Base [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity ($)									$ 700,000,000

CAPITAL LEASES (Details)

CAPITAL LEASES (Details) $ in Thousands	Dec. 31, 2015USD ($)
Capital Leased Assets [Line Items]
Vehicles	$ 1,601
Accumulated depreciation	211
Total leased assets, Net	$ 1,390

CAPITAL LEASES Future Minimum L

CAPITAL LEASES Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2015USD ($)
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 1,665
Less Executory Costs	70
Less Amounts Representing Interest	202
Present Value of Minimum Lease Payments	1,393
Short-term Capital Lease Obligations	357
Long-term Capital Lease Obligations	1,036
Total Capital Lease Obligations	1,393
2016 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	492
2017 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	492
2018 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 681

ASSET RETIREMENT OBLIGATIONS 66

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance beginning of year, January 1	$ 73,855	$ 41,030
Revisions in estimated cash flows	11,658	31,945
Obligations incurred with development activities and assumed with acquisitions	2,373	1,170
Accretion of asset retirement obligation	6,293	3,455	$ 4,747
Obligations discharged with disposal of properties and asset retirements	(4,687)	(3,745)
Balance end of year, December 31	89,492	73,855	$ 41,030
Less: Current portion	(5,460)	(1,863)
Long-term portion	$ 84,032	$ 71,992

EMPLOYEE BENEFIT PLANS Employee

EMPLOYEE BENEFIT PLANS Employee Benefit Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Postretirement Benefit Expense	$ 4.9	$ 3.9	$ 3.7
Deferred Compensation Liability, Current and Noncurrent	1.3	1.5
Deferred Compensation Liability, Current	0.3	0.3
Supplemental Health Care Benefits Liability, Noncurrent	0.8	0.7
Nonqualified deferred compensation for nonemployee directors	$ 0.6	$ 0.3

COMMITMENTS AND CONTINGENCIES68

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MBblsMMcf
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	67,941
Dollar Commitment ($ in thousands) | $	$ 84,619
First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,881
Dollar Commitment ($ in thousands) | $	$ 17,622
Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,854
Dollar Commitment ($ in thousands) | $	$ 17,156
Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,854
Dollar Commitment ($ in thousands) | $	$ 16,324
Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,854
Dollar Commitment ($ in thousands) | $	$ 16,324
commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	28,498
Dollar Commitment ($ in thousands) | $	$ 17,193
Appalachiain Basin
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	47,174
Appalachiain Basin | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,136
Appalachiain Basin | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	18,687
Appalachiain Basin | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Aug. 31, 2022
Utica Shale
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	20,767
Utica Shale | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,745
Utica Shale | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,737
Utica Shale | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,737
Utica Shale | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,737
Utica Shale | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,811
Utica Shale | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Jul. 22, 2023
Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	10,864
Wattenberg Field | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	2,420
Wattenberg Field | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	2,413
Wattenberg Field | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	2,413
Wattenberg Field | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	2,413
Wattenberg Field | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	1,205
Wattenberg Field | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Jun. 30, 2020

COMMITMENTS AND CONTINGENCIES M

COMMITMENTS AND CONTINGENCIES Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2015USD ($)
Minimum Future Lease Payments under Non-cancelable Operating Leases [Line Items]
2,016	$ 2,353
2,017	2,166
2,018	1,975
2,019	1,937
2,020	1,967
Thereafter	124
Total	$ 10,522

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES Additional information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Accrued Environmental Liabilities		$ 4,100,000	$ 800,000
Operating Lease Expense		9,800,000	7,000,000	$ 7,000,000
Partnership Class Action [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount			$ 37,500,000
EPA Notice of Intent [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount		152,000
Gas Marketing Segment
Loss Contingencies [Line Items]
Allowance for Doubtful Accounts Receivable		$ 500,000
PDC Payment | Partnership Class Action [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 31,500,000
Insurance Payment | Partnership Class Action [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 6,000,000

COMMON STOCK Stockholders' Equi

COMMON STOCK Stockholders' Equity Note (Details) - USD ($)	Aug. 19, 2013	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share			$ 0.01	$ 0.01
Common Stock, Value, Issued			$ 402,000	$ 359,000
Additional paid-in capital			$ 907,382,000	$ 689,209,000
March 2015 Common Stock Issuance
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues		4,002,000
Common Stock, Par or Stated Value Per Share		$ 0.01
Sale of Stock, Price Per Share		$ 50.73
Proceeds from Issuance of Common Stock		$ 202,900,000
Common Stock, Value, Issued		40,020
Additional paid-in capital		$ 202,800,000
August 2013 Common Stock Issuance
Class of Stock [Line Items]
Stock Issuance Date	Aug. 19, 2013
Stock Issued During Period, Shares, New Issues	5,175,000
Common Stock, Par or Stated Value Per Share	$ 0.01
Sale of Stock, Price Per Share	$ 53.37
Proceeds from Issuance of Common Stock	$ 275,800,000
Common Stock, Value, Issued	51,750
Additional paid-in capital	$ 275,800,000

COMMON STOCK Stock based compen

COMMON STOCK Stock based compensation plans (Details) - shares	Dec. 31, 2015	Dec. 31, 2014	Jun. 29, 2010
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Common Stock, Shares Authorized	150,000,000	150,000,000	3,000,000
Common stock shares remain avaliable for issuance	1,101,831

COMMON STOCK Stocked Based Comp

COMMON STOCK Stocked Based Compensation Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 20,068	$ 17,518	$ 12,880
Income tax benefit	(7,636)	(5,955)	(4,697)
Net stock-based compensation expense	$ 12,432	$ 11,563	$ 8,183

COMMON STOCK SARs Fair Value As

COMMON STOCK SARs Fair Value Assumptions (Details) - Stock Appreciation Rights (SARs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.
Expected term of award	5 years 2 months 14 days	6 years	6 years
Risk-free interest rate	1.40%	2.10%	1.00%
Expected Volatility	58.00%	65.60%	65.50%
Weighted-average grant date fair value per share	$ 22.23	$ 29.96	$ 21.96

COMMON STOCK Schedule of Change

COMMON STOCK Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Number of SARs
Outstanding beginning of year, January 1,	279,011	190,763	118,832
Awarded	68,274	88,248	87,078
Exercised	(20,832)	0	(15,147)
Outstanding end of year, December 31,	326,453	279,011	190,763
Exercisable at December 31,				222,489	139,334	51,922
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding beginning of year, January 1,	$ 38.77	$ 33.77	$ 30.80
Awarded	39.63	49.57	37.18
Exercised	38.05	0	30.06
Outstanding end of year, December 31,	$ 38.99	$ 38.77	$ 33.77
Exercisable at December 31,				$ 37.70	$ 36.27	$ 29.97
Weighted-Average Remaining Contractual Term (in years)
Outstanding at December 31,	7 years 3 months 7 days	7 years 9 months 20 days
Exercisable at December 31,	6 years 10 months
Share based compesation aggregate intrinsic valu [Roll Forward]
Outstanding beginning of year, January 1,	$ 4,697	$ 1,472	$ 3,711	$ 4,697	$ 1,472	$ 3,711	$ 486
Awarded	0	0	0
Exercised	473	0	425
Outstanding end of year, December 31,	$ 4,697	$ 1,472	$ 3,711
Exercisable at December 31,				3,489	$ 982	$ 1,207
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized				$ 1,700
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 5 months

COMMON STOCK Schedule of Chan76

COMMON STOCK Schedule of Changes in Restricted Stock - TIme Based Awards (Details) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date that a participant is continuously employed.
Time based shares granted to executives	80,707
Number of Shares
Outstanding beginning of year, January 1,	564,332
Granted	313,639
Vested	(333,167)
Forfeited	(19,723)
Outstanding end of year, December 31,	525,081	564,332
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 46.02
Weighted-average grant date fair value per share	48.88	$ 56.45	$ 45.53
Vested	41.59
Forfeited	54.29
Outstanding at end of year, December 31,	$ 50.23	$ 46.02
Total intrinsic value of time based awards vested	$ 17,077	$ 18,278	$ 13,640
Total intrinsic value of time-based awards non-vested	$ 28,029	$ 23,290	$ 34,688
Market price per common share as of December 31,	$ 53.38	$ 41.27	$ 53.22
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 16,400
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 8 months 22 days

COMMON STOCK Restricted Stock -

COMMON STOCK Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - Restricted Stock - Market Based Awards [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term of award	3 years	3 years
Risk-free interest rate	0.90%	0.80%
Expected Volatility	53.00%	55.20%
Weighted-average grant date fair value per share	$ 66.16	$ 56.87	$ 49.04

COMMON STOCK Schedule of Chan78

COMMON STOCK Schedule of Changes in Restricted Stock - Market Based Awards (Details) - Restricted Stock - Market Based Awards [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total intrinsic value of time based awards vested	$ 4,293	$ 1,260	$ 724
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
Time based shares granted to executives	29,398
Number of Shares
Outstanding beginning of year, January 1,	83,721
Granted	29,398
Vested	(41,570)
Outstanding end of year, December 31,	71,549	83,721
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 52.98
Weighted-average grant date fair value per share	66.16	$ 56.87	$ 49.04
Vested	49.04
Outstanding at end of year, December 31,	$ 63.60	$ 52.98
Total intrinsic value of market-based awards non-vested	$ 3,819	$ 3,455	$ 3,838
Market price per common share as of December 31,	$ 53.38	$ 41.27	$ 53.22
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 1,900
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 4 months 24 days

COMMON STOCK Treasury Shares (D

COMMON STOCK Treasury Shares (Details) - Treasury Stock [Member]	12 Months Ended
	Dec. 31, 2015shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury Stock, Shares, Acquired	136,168
Treasury stock acquired and reissued	127,159
Treasury stock acquired, and available for reissuance	9,009

COMMON STOCK Preferred Stock (D

COMMON STOCK Preferred Stock (Details) - shares	Dec. 31, 2015	Dec. 31, 2014	Jun. 23, 2008
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Shares Authorized			50,000,000
Preferred Stock, Shares Issued	0

EARNINGS PER SHARE Earnings Per

EARNINGS PER SHARE Earnings Per Share (Details) shares in Thousands	Nov. 15, 2010shares$ / shares	Dec. 31, 2015shares	Sep. 30, 2015shares	Jun. 30, 2015shares	Mar. 31, 2015shares	Dec. 31, 2014shares	Sep. 30, 2014shares	Jun. 30, 2014shares	Mar. 31, 2014shares	Dec. 31, 2015shares	Dec. 31, 2014shares	Dec. 31, 2013shares
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic		40,094	40,085	40,035	36,349	35,847	35,834	35,762	35,690	39,153	35,784	32,426
Weighted Average Number of Shares Outstanding - Diluted		41,264	40,085	40,035	36,981	36,146	36,828	35,762	35,690	39,153	36,678	32,426
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount										1,494	34	1,424
Restricted Stock [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements										0	279	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount										831	8	823
3.25% Convertible Note [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements										0	564	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount										562	0	518
Other Equity-Based Awards
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements										0	51	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount										101	26	83
Convertible Debt
Convertible Senior Note Due 2016
3.25% Convertible Note, Number of Shares Convertible	2,700
3.25% Convertible Note, Conversion Price | $ / shares	$ 42.40

ASSETS HELD FOR SALE, DIVESTI82

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Discontinued Operations and Disposal Groups (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Lease operating expenses	$ 14,244	$ 13,824	$ 12,639	$ 16,285	$ 11,050	$ 11,020	$ 11,961	$ 8,371	$ 56,992	$ 42,402	$ 33,817
Production taxes	5,237	5,476	3,837	3,893	2,950	8,724	7,551	6,390	18,443	25,615	21,758
Transportation, gathering and processing expenses	3,567	3,938	1,308	1,338	1,331	1,208	818	1,235	10,151	4,592	5,152
Impairment of Natural Gas and Crude Oil Properties									0	433	929
Income (loss) from discontinued operations, net of tax	$ 0	$ 0	$ 0	$ 0	$ 47,782	$ (80)	$ 1,191	$ (719)	0	48,174	(1,190)
Supplemental Cash Flows Information
Capital expenditures									(604,668)	(628,592)	(394,948)
Change in accounts payable related to purchases of properties and equipment									(45,230)	39,667	33,328
Net Assets Related to Discontinued Operations [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Natural gas, NGL and crude oil sales									24,149	39,001
Sales from natural gas marketing									0	2,825
Commodity price risk management gain (loss), net									(1,085)	14
Well operations, pipeline income and other									48	922
Disposal Group, Discontinued Operations, Total revenue									23,112	42,762
Lease operating expenses									1,280	6,522
Production taxes									1,579	3,716
Transportation, gathering and processing expenses									3,536	5,283
Cost of natural gas marketing									0	2,673
Impairment of Natural Gas and Crude Oil Properties									433	954
Depreciation, depletion and amortization									9,128	13,894
Accretion of ARO and other, Discontinued Operations									4,170	8,235
(Gain) loss on sale of properties and equipment									(76,479)	1,700
Total costs, expenses and other									(56,353)	42,977
Disposal Group, Including Discontinued Operation, Interest Expense									(2,222)	(1,755)
Disposal Group, Including Discontinued Operation, Interest Income									194	10
Income (loss) from discontinued operations									77,437	(1,960)
Income taxes (expense) benefit									(29,263)	770
Income (loss) from discontinued operations, net of tax									$ 48,174	(1,190)
PDCM Divestiture [Member]
Supplemental Cash Flows Information
Capital expenditures										(17,253)	(45,277)
Change in accounts payable related to purchases of properties and equipment										$ (5,727)	$ (4,738)

ASSETS HELD FOR SALE, DIVESTI83

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Additional Information (Details) - USD ($) $ in Thousands	Oct. 15, 2014	Dec. 31, 2015	Dec. 31, 2014	Oct. 14, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Real Estate Held-for-sale		$ 2,874	$ 2,874
Segment, Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain/loss on sale		$ 76,479	$ (1,700)
PDCM Divestiture [Member] | PDCM Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership Interest in Joint Venture				50.00%
Divestiture Sale Price After Adjustment	$ 192,000
Cash proceeds from PDCM divestiture	153,000
Promissory note	39,000
Gain/loss on sale	$ 76,300

TRANSACTIONS WITH AFFILIATES 84

TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES Transactions with Affiliates and Other Related Parties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
PDCM
Related Party Transaction [Line Items]
Related party transactions included in cost of natural gas marketing	$ 23,200	$ 18,100
Well operating and administrative services on behalf of PDCM	5,700	14,500
Due from PDCM	$ 0
Affiliated Partnerships
Related Party Transaction [Line Items]
Related party transactions included in cost of natural gas marketing		$ 1,300

BUSINESS SEGMENTS Business se85

BUSINESS SEGMENTS Business segments (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenues	$ 168,634	$ 231,100	$ 50,960	$ 144,632	$ 407,691	$ 224,556	$ 101,303	$ 122,657	$ 595,326	$ 856,207	$ 392,665
Segment income (loss) before income taxes	5,274	$ (62,661)	$ (76,986)	$ 27,785	138,085	$ 89,473	$ (48,028)	$ (2,302)	(106,588)	177,228	(32,963)
Expenditures for segment long-lived assets									604,668	628,592	404,606
Segment assets	2,370,543				2,331,140				2,370,543	2,331,140
Oil and Gas Properties
Segment Reporting Information [Line Items]
Total revenues									584,406	784,636	322,878
Segment income (loss) before income taxes									31,429	344,149	81,913
Expenditures for segment long-lived assets									599,617	623,912	403,227
Segment assets	2,294,288				2,258,060				2,294,288	2,258,060
Marketing
Segment Reporting Information [Line Items]
Total revenues									10,920	71,571	69,787
Segment income (loss) before income taxes									(797)	(445)	(297)
Segment assets	4,217				6,979				4,217	6,979
Corporate and Other
Segment Reporting Information [Line Items]
Segment income (loss) before income taxes									(137,220)	(166,476)	(114,579)
Expenditures for segment long-lived assets									5,051	4,680	$ 1,379
Segment assets	69,164				63,227				69,164	63,227
Assets Held-for-sale
Segment Reporting Information [Line Items]
Segment assets	$ 2,874				$ 2,874				$ 2,874	$ 2,874

BUSINESS SEGMENTS Additional In

BUSINESS SEGMENTS Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Crude oil and natural gas segment
Depreciation, depletion and amortization from continuing operations	$ 96,385	$ 80,947	$ 70,106	$ 55,820	$ 50,363	$ 49,640	$ 49,636	$ 42,889	$ 303,258	$ 192,528	$ 115,624
Oil and Gas Properties
Crude oil and natural gas segment
Depreciation, depletion and amortization from continuing operations									$ 298,800	$ 188,500	$ 111,600

SUPPLEMENTAL INFORMATION - NA87

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Prices Used to Estimate Reserves (Unaudited) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Crude Oil (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	$ 42.10	$ 84.65	$ 82.18
Natural Gas (Mcf)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	2.05	3.92	3.22
Natural Gas Liquids (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	$ 12.23	$ 32.27	$ 29.92

SUPPLEMENTAL INFORMATION - NA88

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Changes in Estimated Proved Reserves (Unaudited) (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2015Mcfbbl	Dec. 31, 2014Mcfbbl	Dec. 31, 2013Mcfbbl		Dec. 31, 2012Mcfbbl
Reserve Quantities [Line Items]
Proved Reserves	272,825	250,129	265,774		192,810
Production	(15,369)	(9,294)	(7,430)
Undeveloped Reserves Converted to Developed	0	0	0
Purchases of Reserves	76	17	1,043
Dispositions	(34)	(39,572)	(16,104)
Extensions, Discoveries, and Other Additions	131,494	98,029	141,935
Revisions of Previous Estimates	(93,471)	(64,825)	(46,480)
Crude Oil (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	98,975	100,515	93,830	[1]	59,310	[2]
Production	(6,984)	(4,322)	(2,910)
Purchases of Reserves	17	5	343
Dispositions	(12)	(13)	(252)
Extensions, Discoveries, and Other Additions	48,707	40,792	55,759
Revisions of Previous Estimates	(43,268)	(29,777)	(18,420)
Proved Developed Reserves	26,257	26,798	23,997	[1]	20,412	[2]
Proved Undeveloped Reserve	72,718	73,717	69,833	[1]	38,898	[2]
Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves | Mcf	660,737	536,972	739,640	[1]	604,038	[2]
Production | Mcf	(33,302)	(19,298)	(20,860)
Purchases of Reserves | Mcf	215	43	2,894
Dispositions | Mcf	(82)	(237,306)	(94,927)
Extensions, Discoveries, and Other Additions | Mcf	311,709	202,957	365,563
Revisions of Previous Estimates | Mcf	(154,775)	(149,064)	(117,068)
Proved Developed Reserves | Mcf	175,367	186,633	220,387	[1]	281,925	[2]
Proved Undeveloped Reserve | Mcf	485,370	350,339	519,253	[1]	322,113	[2]
Natural Gas Liquids (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	63,727	60,119	48,671	[1]	32,827	[2]
Production	(2,835)	(1,756)	(1,043)
Purchases of Reserves	23	5	217
Dispositions	(8)	(8)	(30)
Extensions, Discoveries, and Other Additions	30,835	23,411	25,249
Revisions of Previous Estimates	(24,407)	(10,204)	(8,549)
Proved Developed Reserves	15,011	17,002	14,825	[1]	14,353	[2]
Proved Undeveloped Reserve	48,716	43,117	33,846	[1]	18,474	[2]
Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves	272,825	250,129	265,774	[1]	192,810	[2]
Production	(15,369)	(9,294)	(7,430)
Purchases of Reserves	76	17	1,043
Dispositions	(34)	(39,572)	(16,104)
Extensions, Discoveries, and Other Additions	131,494	98,029	141,935
Revisions of Previous Estimates	(93,471)	(64,825)	(46,480)
Proved Developed Reserves	70,496	74,905	75,553	[1]	81,753	[2]
Proved Undeveloped Reserve	202,329	175,224	190,221	[1]	111,058	[2]
Piceance and NECO Asset Group [Member] | Crude Oil (Bbls)
Reserve Quantities [Line Items]
Proved Developed Reserves					148
Piceance and NECO Asset Group [Member] | Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Developed Reserves | Mcf					83,656
Piceance and NECO Asset Group [Member] | Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Developed Reserves					14,091
Marcellus Shale Asset Group | Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves | Mcf			235,950
Proved Developed Reserves | Mcf			53,904
Proved Undeveloped Reserve | Mcf			182,046
Marcellus Shale Asset Group | Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves			39,325
Proved Developed Reserves			8,984
Proved Undeveloped Reserve			30,341
Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Proved Reserves	70,496	74,905	75,553		81,753
Production	(15,369)	(9,294)	(7,430)
Undeveloped Reserves Converted to Developed	29,090	12,730	3,212
Purchases of Reserves	76	17	1,043
Dispositions	(34)	(9,231)	(16,104)
Extensions, Discoveries, and Other Additions	8,703	27,957	19,830
Revisions of Previous Estimates	(26,875)	(22,827)	(6,751)
Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved Reserves	202,329	175,224	190,221		111,057
Production	0	0	0
Undeveloped Reserves Converted to Developed	(29,090)	(12,730)	(3,212)
Purchases of Reserves	0	0	0
Dispositions	0	(30,341)	0
Extensions, Discoveries, and Other Additions	122,791	70,072	122,105
Revisions of Previous Estimates	(66,596)	(41,998)	(39,729)
[1]	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.
[2]	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.

SUPPLEMENTAL INFORMATION - NA89

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Schedule of Developed and Undeveloped Reserves (Unaudited) (Details) bbl in Thousands, Boe in Millions	12 Months Ended
	Dec. 31, 2016Rate	Dec. 31, 2015BoeRatebbl	Dec. 31, 2014BoeRatebbl	Dec. 31, 2013Ratebbl		Dec. 31, 2012bbl
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net		272,825	250,129	265,774		192,810
Undeveloped Reserves Converted to Developed		0	0	0
Revisions of Previous Estimates		(93,471)	(64,825)	(46,480)
Extensions, Discoveries, and Other Additions		131,494	98,029	141,935
Purchases of Reserves		76	17	1,043
Dispositions		(34)	(39,572)	(16,104)
Production		(15,369)	(9,294)	(7,430)
Crude Oil Equivalent (Boe)
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net		272,825	250,129	265,774	[1]	192,810	[2]
Revisions of Previous Estimates		(93,471)	(64,825)	(46,480)
Extensions, Discoveries, and Other Additions		131,494	98,029	141,935
Purchases of Reserves		76	17	1,043
Dispositions		(34)	(39,572)	(16,104)
Production		(15,369)	(9,294)	(7,430)
Year-over-Year Activity [Domain]
Schedule of Developed and Undeveloped Reserves [Line Items]
Undeveloped Reserves Converted to Developed		29,000	13,000	3,000
Revisions of Previous Estimates		93,000	(65,000)	46,000
Extensions, Discoveries, and Other Additions		131,000	98,000	142,000
Wells Per Section		16
Gross PUD horizontal locations		791	774
Purchases of Reserves				1,000
Dispositions			(40,000)	(16,000)
Increase (decrease) in proved reserves | Boe		23	(16)
Estimated PUD conversion rate | Rate		16.00%	7.00%	15.00%
Actual PUD conversion rate | Rate	19.00%	17.00%	7.00%	3.00%
Majority of downward revision of our previous estimate of proved reserves				(55,000)
Change in drilling plans		(56,000)	(55,000)
Upward (Downward) Revision due to change in SEC pricing		(33,000)
Upward (Downward) Revision due to removal of re-fracs		(11,000)
Upward (downward) revision due to geological findings		(22,000)
Downward revisions due to adjustments in previous PUD well spacing plans			(2,000)	(32,000)
Downward revisions in reserves due to our shift from vertical to horizontal drilling				(11,000)
Downward revisions Wattenberg Field related to PUDs that are no longer in our core drilling area		(8,000)		(3,000)
Reserve discoveries from non-PUD drilling			16,000	17,000
Extension and discoveries due to adjustments in wells spacing in Wattenberg Field and Marcellus Shale			78,000	125,000
Extension and discoveries in the Marcellus Shale				18,000
Extension and discoveries in the Utica Shale			2,000	14,000
Reserve discoveries, refracs not added in prior year report			2,000
Reserve discoveries, Wattenberg Field				110,000
Developed [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net		70,496	74,905	75,553		81,753
Undeveloped Reserves Converted to Developed		29,090	12,730	3,212
Revisions of Previous Estimates		(26,875)	(22,827)	(6,751)
Extensions, Discoveries, and Other Additions		8,703	27,957	19,830
Purchases of Reserves		76	17	1,043
Dispositions		(34)	(9,231)	(16,104)
Production		(15,369)	(9,294)	(7,430)
Undeveloped [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net		202,329	175,224	190,221		111,057
Undeveloped Reserves Converted to Developed		(29,090)	(12,730)	(3,212)
Revisions of Previous Estimates		(66,596)	(41,998)	(39,729)
Extensions, Discoveries, and Other Additions		122,791	70,072	122,105
Purchases of Reserves		0	0	0
Dispositions		0	(30,341)	0
Production		0	0	0
[1]	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.
[2]	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.

SUPPLEMENTAL INFORMATION - NA90

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Results of Operations for Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Lease operating expenses	$ 14,244	$ 13,824	$ 12,639	$ 16,285	$ 11,050	$ 11,020	$ 11,961	$ 8,371	$ 56,992	$ 42,402	$ 33,817
Production taxes	5,237	5,476	3,837	3,893	2,950	8,724	7,551	6,390	18,443	25,615	21,758
Transportation, gathering and processing expenses	$ 3,567	$ 3,938	$ 1,308	$ 1,338	$ 1,331	$ 1,208	$ 818	$ 1,235	10,151	4,592	5,152
Results of Operations for Crude Oil and Natural Gas Producing Activities
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Natural gas, NGL and crude oil sales									378,713	495,562	379,796
Commodity price risk management									203,183	309,219	(23,905)
Total Revenues from Oil and Gas Producing Activities									581,896	804,781	355,891
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 Oil and 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
Total Expense from Oil and Gas Producing Activities									552,976	376,371	269,817
Results of Operations of Natural Gas and Crude Oil Producing Activities, Income before Income Taxes									28,920	428,410	86,074
Provision for Income Taxes									(10,394)	(166,930)	(31,109)
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs									$ 18,526	$ 261,480	$ 54,965

SUPPLEMENTAL INFORMATION - NA91

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities (Unadited) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved Properties	[1]	$ 3,561	$ 11,973	$ 28,698
Unproved Properties	[1]	15	45,999	3,390
Development Costs	[2]	552,104	608,176	338,294
Exploratory drilling	[3]	0	0	58,988
Geological and geophysical	[3]	0	1	752
Total Costs Incurred		555,680	666,149	430,122
Cost Incurred to Convert PUDs to PDNP		$ 207,800	$ 125,200	$ 40,100
[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.

SUPPLEMENTAL INFORMATION - NA92

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved natural gas and crude oil properties	$ 2,881,189	$ 2,267,165
Unproved natural gas and crude oil 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

SUPPLEMENTAL INFORMATION - NA93

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
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 Disconted Future Estimated Net Cash Flows	$ 1,096,864	$ 2,306,465	$ 1,782,163

SUPPLEMENTAL INFORMATION - NA94

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Principal Sources of Change:
Sales of natural gas, NGL and crude oil production, net of production costs		$ (293,127,000)	$ (387,789,000)	$ (286,021,000)
Net changes in prices and production costs	[1]	(1,752,921,000)	129,213,000	89,527,000
Extensions, discoveries and improved recovery, less related costs	[2]	489,178,000	1,444,581,000	1,529,006,000
Sales of reserves	[3]	(463,000)	(402,595,000)	(142,724,000)
Purchases of reserves	[4]	374,000	238,000	10,610,000
Development costs incurred during the period		368,840,000	161,404,000	46,366,000
Revisions of previous quantity estimates	[5]	(1,286,462,000)	(654,318,000)	(397,738,000)
Changes in estimated income taxes	[6]	902,994,000	(221,874,000)	(381,369,000)
Net change in future development costs		112,958,000	46,499,000	(40,707,000)
Accretion of discount		345,007,000	270,389,000	142,040,000
Timing and other		(95,979,000)	138,554,000	44,676,000
Total		(1,209,601,000)	524,302,000	613,666,000
Notes to Changes in SMOG [Abstract]
Weighted-Average price, net of production cost		$ 17.30	$ 37.78	$ 30.82
Percentage Change in Extensions and Discoveries		(66.00%)	(6.00%)
Long-Term Deferred Tax Rate				38.00%
[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 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.
[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.

SUPPLEMENTAL INFORMATION - QU95

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Natural gas, NGL and crude oil sales	$ 103,193	$ 104,483	$ 96,928	$ 74,109	$ 99,857	$ 120,526	$ 131,017	$ 120,013	$ 378,713	$ 471,413	$ 340,795
Sales from natural gas marketing	2,584	2,580	2,523	3,233	8,922	13,297	22,415	26,937	10,920	71,571	69,787
Commodity price risk management gain (loss), net	62,013	123,549	(49,041)	66,662	297,643	90,213	(52,643)	(24,909)	203,183	310,304	(23,919)
Well operations, pipeline income and other	844	488	550	628	1,269	520	514	616	2,510	2,919	6,002
Total revenues	168,634	231,100	50,960	144,632	407,691	224,556	101,303	122,657	595,326	856,207	392,665
Costs, expenses and other:
Lease operating expenses	14,244	13,824	12,639	16,285	11,050	11,020	11,961	8,371	56,992	42,402	33,817
Production taxes	5,237	5,476	3,837	3,893	2,950	8,724	7,551	6,390	18,443	25,615	21,758
Transportation, gathering and processing expenses	3,567	3,938	1,308	1,338	1,331	1,208	818	1,235	10,151	4,592	5,152
Cost of natural gas marketing	2,842	2,781	2,836	3,258	9,370	13,347	22,428	26,870	11,717	72,015	70,084
Exploration expense	290	252	275	285	174	190	276	307	1,102	947	6,334
Impairment of natural gas and crude oil properties	413	154,031	4,404	2,772	161,914	1,962	2,019	952	161,620	166,847	52,873
General and administrative expense	27,908	20,278	20,728	21,045	20,989	36,328	41,713	24,529	89,959	123,559	63,715
Depreciation, depletion and amortization	96,385	80,947	70,106	55,820	50,363	49,640	49,636	42,889	303,258	192,528	115,624
Accretion of asset retirement obligations	1,551	1,594	1,588	1,560	873	861	840	841	6,293	3,415	4,566
(Gain) loss on sale of Leaseholds	(83)	(74)	(207)	(21)	(70)	21	(23)	579	(385)	507	2,022
Total cost, expenses and other	152,354	283,047	117,514	106,235	258,944	123,301	137,219	112,963	659,150	632,427	375,945
Income from operations	16,280	(51,947)	(66,554)	38,397	148,747	101,255	(35,916)	9,694	(63,824)	223,780	16,720
Interest expense	(12,187)	(12,092)	(11,567)	(11,725)	(11,643)	(11,821)	(12,195)	(12,183)	(47,571)	(47,842)	(50,143)
Interest income	1,181	1,378	1,135	1,113	981	39	83	187	4,807	1,290	460
Income (loss) from continuing operations before income taxes	5,274	(62,661)	(76,986)	27,785	138,085	89,473	(48,028)	(2,302)	(106,588)	177,228	(32,963)
Provision for income taxes	(2,252)	21,167	30,116	(10,723)	(54,115)	(35,396)	18,650	894	38,308	(69,967)	11,852
Income (loss) from continuing operations	3,022	(41,494)	(46,870)	17,062	83,970	54,077	(29,378)	(1,408)	(68,280)	107,261	(21,111)
Income (loss) from discontinued operations, net of tax	0	0	0	0	47,782	(80)	1,191	(719)	0	48,174	(1,190)
Net income (loss)	$ 3,022	$ (41,494)	$ (46,870)	$ 17,062	$ 131,752	$ 53,997	$ (28,187)	$ (2,127)	$ (68,280)	$ 155,435	$ (22,301)
Basic
Income (loss) from continuing operations	$ 0.08	$ (1.04)	$ (1.17)	$ 0.47	$ 2.34	$ 1.51	$ (0.82)	$ (0.04)	$ (1.74)	$ 3	$ (0.65)
Income (loss) from discontinued operations	0	0	0	0	1.33	0	0.03	(0.02)	0	1.34	(0.04)
Net income (loss) attributable to shareholders	0.08	(1.04)	(1.17)	0.47	3.67	1.51	(0.79)	(0.06)	(1.74)	4.34	(0.69)
Diluted
Income (loss) from continuing operations	0.07	(1.04)	(1.17)	0.46	2.32	1.47	(0.82)	(0.04)	(1.74)	2.93	(0.65)
Income (loss) from discontinued operations	0	0	0	0	1.32	0	0.03	(0.02)	0	1.31	(0.04)
Net income (loss) attributable to shareholders	$ 0.07	$ (1.04)	$ (1.17)	$ 0.46	$ 3.64	$ 1.47	$ (0.79)	$ (0.06)	$ (1.74)	$ 4.24	$ (0.69)
Weighted-average common shares outstanding
Basic	40,094	40,085	40,035	36,349	35,847	35,834	35,762	35,690	39,153	35,784	32,426
Diluted	41,264	40,085	40,035	36,981	36,146	36,828	35,762	35,690	39,153	36,678	32,426

SCHEDULE II- VALUATION AND QUAL

SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for Doubtful Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		$ 486	$ 896	$ 718
Charged to Cost and Expense		1,700	78	322
Deductions	[1]	177	488	144
Ending Balance, December 31		2,009	486	896
Valuation Allowance for Unproved Natural Gas and Crude Oil Properties [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		9,293	5,142	5,690
Charged to Cost and Expense		7,012	4,465	3,038
Deductions	[1]	16,161	314	3,586
Ending Balance, December 31		$ 144	$ 9,293	$ 5,142
[1]	For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.