PDC Energy (PDCE) 10-K19 Feb 152013 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information Document Document (USD $)	12 Months Ended
Document and Entity Information Document Document (USD $)	Dec. 31, 2014	Feb. 07, 2014	Jun. 30, 2013
Entity Information [Line Items]
Entity Registrant Name	PDC ENERGY, INC.
Entity Central Index Key	77877
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-13
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		35,991,142
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$2,237,411,889

Consolidated_Balance_Sheets_Au

Consolidated Balance Sheets (Audited) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$16,066	$192,642
Restricted cash	0	2,211
Accounts receivable, net	131,204	88,111
Accounts receivable affiliates	512	6,614
Derivative Instruments and Hedges, Assets	187,495	1,521
Deferred income taxes	0	22,374
Assets held for sale	0	7,661
Prepaid expenses and other current assets	5,442	4,679
Total current assets	340,719	325,813
Properties and equipment, net	1,800,186	1,480,986
Assets held for sale	2,874	182,136
Fair value of derivatives	112,819	4,503
Other assets	83,990	31,765
Total Assets	2,340,588	2,025,203
Current liabilities:
Accounts payable	130,321	101,688
Accounts payable affiliates	0	41
Production tax liability	21,314	22,232
Fair value of derivatives	570	14,689
Funds held for distribution	27,186	31,040
Accrued interest payable	9,109	9,033
Deferred income taxes	59,174	0
Liabilities held for sale	0	12,069
Liabilities held for sale	0	55,915
Other accrued expenses	62,717	22,628
Total current liabilities	310,391	213,420
Long-term debt	664,923	604,990
Deferred income taxes	125,693	118,767
Asset retirement obligations	71,992	37,638
Fair value of derivatives	197	2,842
Other liabilities	30,033	24,037
Total liabilities	1,203,229	1,057,609
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, 35,927,985 and 35,675,656 issued as of December 31, 2014 and 2013, respectively	359	357
Additional paid-in capital	689,209	674,211
Retained earnings	448,702	293,267
Treasury shares - at cost, 21,643 and 5,508 as of December 31, 2014 and 2013, respectively	-911	-241
Total shareholders' equity	1,137,359	967,594
Total Liabilities and Shareholders' Equity	$2,340,588	$2,025,203

Balance_Sheet_Parentheticals_P

Balance Sheet Parentheticals (Parentheticals) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Balance Sheet Parentheticals [Abstract]
Common Stock, Par or Stated Value Per Share	$0.01	$0.01
Common Stock, Shares Authorized	150,000,000	100,000,000
Common Stock, Shares, Issued	35,927,985	35,675,656
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	21,643	5,508

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (Audited) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Natural gas, NGL and crude oil sales	$99,857	$120,526	$131,017	$120,013	$113,810	$77,340	$73,695	$75,950	$471,413	$340,795	$227,990
Sales from natural gas marketing	8,922	13,297	22,415	26,937	21,092	16,946	18,079	13,670	71,571	69,787	45,371
Commodity price risk management gain (loss), net	297,643	90,213	-52,643	-24,909	-1,844	-24,138	21,828	-19,765	310,304	-23,919	29,279
Well operations, pipeline income and other	1,269	520	514	616	2,321	1,667	954	1,060	2,919	6,002	4,496
Total revenues	407,691	224,556	101,303	122,657	135,379	71,815	114,556	70,915	856,207	392,665	307,136
Costs, expenses and other:
Production costs	19,013	22,754	23,774	18,083	19,159	17,036	14,274	14,381	83,624	64,850	49,383
Cost of natural gas marketing	9,370	13,347	22,428	26,870	21,156	17,127	18,065	13,736	72,015	70,084	45,023
Exploration expense	174	190	276	307	1,687	1,841	1,266	1,540	947	6,334	18,202
Impairment of natural gas and crude oil properties	159,911	1,863	848	910	715	4,236	1,298	46,260	163,532	52,509	5,020
General and administrative expense	19,310	34,625	39,440	22,484	16,018	15,052	14,849	14,037	115,859	59,956	54,817
Depreciation, depletion and amortization	50,363	49,640	49,636	42,889	37,748	26,957	25,488	25,431	192,528	115,624	91,111
Accretion of asset retirement obligations	873	861	840	841	1,075	1,181	1,167	1,143	3,415	4,566	3,670
(Gain) loss on sale of Leaseholds	-70	21	-23	579	2,153	-100	-1	-30	507	2,022	-183
Total cost, expenses and other	258,944	123,301	137,219	112,963	99,711	83,330	76,406	116,498	632,427	375,945	267,043
Income from operations	148,747	101,255	-35,916	9,694	35,668	-11,515	38,150	-45,583	223,780	16,720	40,093
Loss on extinguishment of debt									0	0	-23,283
Interest expense	-11,643	-11,821	-12,195	-12,183	-12,260	-11,957	-12,838	-13,088	-47,842	-50,143	-47,505
Interest income	981	39	83	187	327	130	3	0	1,290	460	7
Income (loss) from continuing operations before income taxes	138,085	89,473	-48,028	-2,302	23,735	-23,342	25,315	-58,671	177,228	-32,963	-30,688
Provision for income taxes	-54,115	-35,396	18,650	894	-8,937	9,435	-9,444	20,798	-69,967	11,852	11,333
Income (loss) from continuing operations	83,970	54,077	-29,378	-1,408	14,798	-13,907	15,871	-37,873	107,261	-21,111	-19,355
Income (loss) from discontinued operations, net of tax	47,782	-80	1,191	-719	-1,599	-2,093	4,047	-1,545	48,174	-1,190	-111,357
Net income (loss)	$131,752	$53,997	($28,187)	($2,127)	$13,199	($16,000)	$19,918	($39,418)	$155,435	($22,301)	($130,712)
Basic
Income (loss) from continuing operations	$2.34	$1.51	($0.82)	($0.04)	$0.42	($0.42)	$0.53	($1.25)	$3	($0.65)	($0.70)
Income (loss) from discontinued operations	$1.33	$0	$0.03	($0.02)	($0.04)	($0.06)	$0.13	($0.05)	$1.34	($0.04)	($4.02)
Net income (loss) attributable to shareholders	$3.67	$1.51	($0.79)	($0.06)	$0.38	($0.48)	$0.66	($1.30)	$4.34	($0.69)	($4.72)
Diluted
Income (loss) from continuing operations	$2.32	$1.47	($0.82)	($0.04)	$0.40	($0.42)	$0.51	($1.25)	$2.93	($0.65)	($0.70)
Income (loss) from discontinued operations	$1.32	$0	$0.03	($0.02)	($0.04)	($0.06)	$0.13	($0.05)	$1.31	($0.04)	($4.02)
Net income (loss) attributable to shareholders	$3.64	$1.47	($0.79)	($0.06)	$0.36	($0.48)	$0.64	($1.30)	$4.24	($0.69)	($4.72)
Weighted-average common shares outstanding:
Basic	35,847	35,834	35,762	35,690	35,620	33,413	30,332	30,270	35,784	32,426	27,677
Diluted	36,146	36,828	35,762	35,690	36,836	33,413	31,014	30,270	36,678	32,426	27,677

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (Audited) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	$155,435	($22,301)	($130,712)
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled derivatives	-311,281	36,801	17,134
Depreciation, depletion and amortization	201,656	129,518	146,879
Impairment of natural gas and crude oil properties	163,965	53,438	168,149
Prepaid well write-offs	3,062	74	3,916
Loss on extinguishment of debt	0	0	23,283
Exploratory dry hole costs	0	0	15,347
Accretion of asset retirement obligation	3,455	4,747	4,060
Stock-based compensation	17,518	12,880	8,495
Excess tax benefits from stock-based compensation	-1,999	-2,489	0
(Gain) loss from sale of properties and equipment	75,972	-3,722	24,273
Amortization of debt discount and issuance costs	6,938	6,783	7,864
Deferred income taxes	88,474	-15,883	-80,379
Inventory adjustment and other	-1,076	460	4,123
Total adjustments to net income (loss) to reconcile to net cash provided by operating activities:	94,740	230,051	294,598
Changes in current assets and liabilities:
Accounts receivable	-34,598	-41,509	6,843
Other assets	-3,296	3,461	-2,908
Restricted cash	2,214	-8	8,859
Production tax liability	3,358	4,121	2,499
Accounts payable and accrued expenses	21,453	-11,485	-5,050
Other liabilities	-2,617	-3,165	592
Total changes in current assets and liabilities	-13,486	-48,585	10,835
Net cash provided by operating activities	236,689	159,165	174,721
Cash flows from investing activities:
Capital expenditures	-628,592	-394,948	-347,729
Acquisition of natural gas and crude oil properties, net of cash acquired	0	-9,658	-312,223
Proceeds from acquisition adjustments	0	7,579	14,469
Proceeds from sale of properties and equipment	154,457	179,919	193,544
Net cash used in investing activities	-474,135	-217,108	-451,939
Cash flows from financing activities:
Proceeds from credit facility	263,750	260,250	682,000
Payment of credit facility	200,000	283,500	839,750
Proceeds from senior notes	0	0	500,000
Repurchase of senior notes	0	0	-221,840
Payment of debt issuance costs	-88	-2,352	-11,969
Proceeds from sale of equity, net of issuance costs	0	275,847	164,496
Excess tax benefits from stock-based compensation	1,999	2,489	0
Purchase of treasury stock	-5,392	-4,133	-1,500
Proceeds from exercise of stock options	0	128	0
Net cash provided by (used in) financing activities	60,269	248,729	271,437
Net increase (decrease) in cash and cash equivalents	-177,177	190,786	-5,781
Cash and cash equivalents, beginning of year	193,243	2,457	8,238
Cash and cash equivalents, end of year	16,066	193,243	2,457
Cash payments (receipts) for:
Interest, net of capitalized interest	46,809	48,844	41,768
Income taxes	1,800	-3,014	1,845
Non-cash investing activities:
Change in accounts payable related to purchases of properties and equipment	39,667	33,328	288
Change in asset retirement obligation, with a corresponding increase to natural gas and crude oil properties, net of disposals	33,250	2,112	11,967
Change in accounts receivable related to disposition of properties and equipment	0	808	0
Change in other assets related to disposition of properties and equipment	$39,048	$3,350	$0

Consolidated_Statement_of_Equi

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 Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2011				$236,000	$217,707,000	$446,280,000	($111,000)
Shares issued pursuant to sale of equity				6,500,000
Exercise of stock options				0
Issuance of stock awards, net of forfeitures				173,737
Retirement of treasury shares				-14,471			-14,471
Purchase of treasury shares							44,576
Issuance of treasury shares							-28,587
Non-employee directors' deferred compensation plan							603
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity				65,000	164,431,000
Purchase of treasury shares							-1,500,000
Issuance of stock awards, net of forfeitures				2,000
Exercise of stock options					0
Share-based Compensation expense	8,495,000				8,495,000
Issuance of treasury shares					-955,000		955,000
Retirement of treasury shares					-491,000		491,000
Tax benefit (detriment) of stock-based compensation					-1,693,000
Non-employee directors' deferred compensation plan							-19,000
Net income (Loss) attributable to shareholders	-130,712,000					-130,712,000
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2012		703,181,000	0	303,000	387,494,000	315,568,000	-184,000
Shares, Issued at Dec. 31, 2012				30,294,224			5,059
Shares end of year at Dec. 31, 2012				30,289,165
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
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
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		357,000	674,211,000	293,267,000	-241,000
Shares, Issued at Dec. 31, 2013				35,675,656			5,508
Shares end of year at Dec. 31, 2013				35,670,148
Shares issued pursuant to sale of equity				0
Exercise of stock options				0
Issuance of stock awards, net of forfeitures				253,032
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
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)
Shares, Issued at Dec. 31, 2014				35,927,985			21,643
Shares end of year at Dec. 31, 2014				35,906,342

NATURE_OF_OPERATIONS_AND_BASIS

NATURE OF OPERATIONS AND BASIS OF PRESENTATION	12 Months Ended
NATURE OF OPERATIONS AND BASIS OF PRESENTATION	Dec. 31, 2014
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract]
Nature of Operations [Text Block]	NATURE OF OPERATIONS AND BASIS OF PRESENTATION

	PDC Energy, Inc. 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, the Utica Shale in southeastern Ohio and, until the fourth quarter of 2014, the Marcellus Shale in northern West Virginia. 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, 2014, we owned an interest in approximately 2,900 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 PDC Mountaineer, LLC ("PDCM") to an unrelated third-party. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information.

	The consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of PDCM (until the fourth quarter of 2014) and our affiliated partnerships. As of December 31, 2014, 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.

	Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are attributable to reporting as discontinued operations the results of operations related to PDCM's Marcellus Shale assets and reporting as held for sale our proportionate share of PDCM's Marcellus Shale assets and liabilities, as well as a parcel of land. 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, 2014
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, 2014, we had collateral in the form of certificates of deposit and cash totaling $0.7 million included in other assets. As of December 31, 2013, we had collateral in the form of certificates of deposit and cash totaling $3.3 million which consisted of $2.2 million and $1.1 million included in restricted cash and other assets, respectively.
	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, 2014 and 2013, inventory of $0.8 million and $0.9 million, respectively, is included in prepaid expenses and other current 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, 2014 and 2013, 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.

	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. Total impairments to other property and equipment was $0.8 million in 2014. There were no impairments to other property and equipment in 2013 or 2012.

	The following table presents the estimated useful lives of our other property and equipment:



	Pipelines and related facilities	10 - 17 years
	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 $4.1 million, $4.0 million and $4.8 million in 2014, 2013 and 2012, 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 $3.5 million, $1.7 million and $0.9 million in 2014, 2013 and 2012, 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 to production costs. 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 $26.4 million and $22.1 million in December 31, 2014 and 2013, 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, 2014 and 2013, 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. As of December 31, 2014 and 2013, included in other assets were $13.7 million and $16.6 million, respectively, related to debt issuance costs. 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. The December 31, 2013 amount included $1.3 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $9.8 million related to our 7.75% senior notes due 2022 and $5.5 million related to our revolving credit facility and the PDCM 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 9, 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. We currently use the "net-back" method of accounting for crude oil, natural gas and NGLs production from the Wattenberg Field and 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. Natural gas and NGLs sales related to production from the Utica Shale are recognized based on gross prices as the purchasers do not provide transportation, gathering or processing services and we recognize expenses relating to those services as production costs.

	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 2014, 2013 and 2012.

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.

Recent Accounting Standards.

Recently Adopted Accounting Standard. On January 1, 2014, we adopted changes issued by the Financial Accounting Standards Board ("FASB") regarding the accounting for income taxes. The change provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. Adoption of these changes had no impact on the consolidated financial statements.

In April 2014, the FASB issued changes related to the criteria for determining which disposals can be presented as discontinued operations and modified related disclosure requirements. Under the new pronouncement, a discontinued operation is defined as a component of an entity that either has been disposed of or is classified as held for sale and represents a strategic shift that has a major effect on the entity's operations and financial results. These changes were required to be applied prospectively for new disposals or components of an entity classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. On July 1, 2014, we elected to early adopt the new pronouncement.

Recently Issued Accounting Standard. In May 2014, the FASB and the International Accounting Standards Board ("IASB") 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: (a) identify the contract with the customer, (b) identify the separate performance obligations in the contract, (c) determine the transaction price, (d) allocate the transaction price to separate performance obligations and (e) recognize revenue when (or as) each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and can be adopted under the full retrospective method or simplified transition method. Early adoption is not permitted. We plan to adopt the revenue standard beginning January 1, 2017 and are currently evaluating the impact these changes will 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. We are currently evaluating the impact these changes will have on our consolidated financial statements.

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 are currently evaluating the impact these changes will have 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. The adoption of this guidance is not expected to have a significant impact on our consolidated financial statements.

FAIR_VALUE_MEASUREMENTS_AND_DI

FAIR VALUE MEASUREMENTS AND DISCLOSURES	12 Months Ended
	Dec. 31, 2014
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,
		2014												2013
		Significant Other				Significant				Total				Significant Other			Significant		Total
		Observable				Unobservable								Observable			Unobservable
		Inputs				Inputs								Inputs			Inputs
		(Level 2)				(Level 3)								(Level 2)			(Level 3)
		(in thousands)
	Assets:
	Commodity-based derivative contracts	$	237,939			$	62,356			$	300,295			$	3,852		$	2,098	$	5,950

	Basis protection derivative contracts	19				—				19				74			—		74

	Total assets	237,958				62,356				300,314				3,926			2,098		6,024

	Liabilities:
	Commodity-based derivative contracts	742				—				742				16,539			987		17,526

	Basis protection derivative contracts	25				—				25				5			—		5

	Total liabilities	767				—				767				16,544			987		17,531

	Net asset (liability)	$	237,191			$	62,356			$	299,547			$	(12,618	)	$	1,111	$	(11,507	)



	The following table presents a reconciliation of our Level 3 assets measured at fair value:



			2014				2013				2012

			(in thousands)



	Fair value, net asset, beginning of period		$	1,111			$	13,610			$	22,107

	Changes in fair value included in statement of operations line item:
	Commodity price risk management gain (loss), net		62,003				(1,748		)		7,517

	Sales from natural gas marketing		(22		)		13				63

	Changes in fair value included in balance sheet line item (1):
	Accounts payable affiliates		—				—				(319		)

Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net		(737		)		(6,361		)		(15,644		)
Sales from natural gas marketing		1				(37		)		(114		)

Loss from discontinued operations, net of tax		—				(4,366		)		—

Fair value, net asset end of period		$	62,356			$	1,111			$	13,610



Net change in fair value of unsettled derivatives included in statement of operations line item:
Commodity price risk management gain (loss), net		$	15,632			$	(2,731	)		$	3,665

Sales from natural gas marketing		3				4				1

Total		$	15,635			$	(2,727	)		$	3,666



__________

-1	Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.

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 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, 2014 and 2013.

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, 2014, 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 $137.5 million, or 119.6% of par value, and the portion related to our 7.75% senior notes due 2022 to be $452.5 million, or 90.5% 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.

DERIVATIVE_FINANCIAL_INSTRUMEN

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2014
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, 2014, we had derivative instruments in place for a portion of our anticipated production through 2017 for a total of 65,215 BBtu of natural gas and 9,340 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, 2014, 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 2014, 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.


	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, 2014 and 2013:



	Derivative instruments:			Balance sheet line item		2014				2013
						(in thousands)
	Derivative assets:	Current
		Commodity contracts
		Related to crude oil and natural gas sales		Fair value of derivatives		$	186,886			$	1,086

		Related to natural gas marketing		Fair value of derivatives		590				361

		Basis protection contracts
		Related to crude oil and natural gas sales		Fair value of derivatives		19				74

						187,495				1,521

		Non-current
		Commodity contracts
		Related to crude oil and natural gas sales		Fair value of derivatives		112,599				4,225

		Related to natural gas marketing		Fair value of derivatives		220				278

						112,819				4,503

	Total derivative assets					$	300,314			$	6,024


	Derivative liabilities:	Current
		Commodity contracts
		Related to crude oil and natural gas sales		Fair value of derivatives		$	—			$	14,437

		Related to natural gas marketing		Fair value of derivatives		545				247

		Basis protection contracts
		Related to crude oil and natural gas sales		Fair value of derivatives		25				—

		Related to natural gas marketing		Fair value of derivatives		—				5

						570				14,689

	Non-current
	Commodity contracts
	Related to crude oil and natural gas sales		Fair value of derivatives		—				2,609

	Related to natural gas marketing		Fair value of derivatives		197				233

					197				2,842

Total derivative liabilities					$	767			$	17,531




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		2014				2013				2012


Commodity price risk management gain (loss), net
Net settlements		$	(837	)		$	11,177			$	43,591

Net change in fair value of unsettled derivatives		311,141				(35,096		)		(14,312		)

Total commodity price risk management gain (loss), net		$	310,304			$	(23,919	)		$	29,279

Sales from natural gas marketing
Net settlements		$	(208	)		$	446			$	2,170

Net change in fair value of unsettled derivatives		364				429				(1,658		)

Total sales from natural gas marketing		$	156			$	875			$	512

Cost of natural gas marketing
Net settlements		$	346			$	(257	)		$	(2,029	)

Net change in fair value of unsettled derivatives		(451		)		(412		)		1,601

Total cost of natural gas marketing		$	(105	)		$	(669	)		$	(428	)



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, 2014 and 2013:


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




As of December 31, 2013		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		$	6,024			$	(4,637	)		$	1,387


Liability derivatives:
Derivative instruments, at fair value		$	17,531			$	(4,637	)		$	12,894

CONCENTRATION_OF_RISK

CONCENTRATION OF RISK	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013
		(in thousands)

	Crude oil, natural gas and NGLs sales	$	49,531		$	61,197

	Joint interest billings	52,841			20,085

	Derivative counterparties	12,582			1,025

	Insurance reimbursement	11,212			—

	Other	5,524			6,700

	Allowance for doubtful accounts	(486		)	(896		)
	Accounts receivable, net	$	131,204		$	88,111



	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, 2014, 2013 and 2012, amounts written off to allowance for doubtful accounts were not material. 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, representing 11.1% and 10.3%, respectively, of our accounts receivable balance.

	Major Customers. The following table presents the individual customers constituting 10% or more of total revenues:



			Year Ended December 31,
	Customer		2014		2013			2012

	Suncor Energy Marketing, Inc.		19.7	%	35.9	%		39.1	%
	Concord Energy		18.3	%	—	%		—	%
	DCP Midstream, LP		15.1	%	13.9	%		16	%
	Teppco Crude Oil, LLC		12.9	%	8	%		2.4	%

	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.

	The following table presents the counterparties that expose us to credit risk as of December 31, 2014, with regard to our derivative assets:



			Fair Value of
			Derivative Assets
	Counterparty Name		As of December 31, 2014
			(in thousands)

	JP Morgan Chase Bank, N.A (1)		$	95,294

	Canadian Imperial Bank of Commerce (1)		61,570

	NATIXIS (1)		45,214

	Wells Fargo Bank, N.A. (1)		41,844

	Key Bank N.A. (1)		24,899

	Bank of Nova Scotia (1)		23,760

Other lenders in our revolving credit facility		7,726

Various (2)		7

Total		$	300,314


____________
(1)Major lender in our revolving credit facility. See Note 8, Long-Term Debt.
(2)Represents a total of 2 counterparties.

Note Receivable
The following table presents information regarding our note receivable outstanding as of December 31, 2014:


	Amount
	(in thousands)
Note Receivable:
Principal outstanding, October 14, 2014	$	39,048

Paid-In-Kind interest	659

Principal outstanding, December 31, 2014	$	39,707


In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 14, 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, 2014, the issuer of the Note had elected to pay-in-kind interest on the Note. 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 without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities issued and certain assets.

Under the effective interest method, we recognized $0.9 million of interest income for the year ended December 31, 2014, of which $0.7 million was PIK Interest. As of December 31, 2014, the $39.7 million 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, 2014
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,
		2014			2013
		(in thousands)
	Properties and equipment, net:
	Crude oil and natural gas properties
	Proved	$	2,267,165		$	1,677,271

	Unproved	188,206			253,464

	Total crude oil and natural gas properties	2,455,371			1,930,735

	Equipment and other	29,562			28,832

	Land and buildings	9,015			9,782

	Construction in progress	137,937			41,180

	Properties and equipment, at cost	2,631,885			2,010,529

	Accumulated DD&A	(831,699		)	(529,543		)
	Properties and equipment, net	$	1,800,186		$	1,480,986



	The following table presents impairment charges recorded for crude oil and natural gas properties:



		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Continuing operations:
	Impairment of proved properties	$	112,557		$	48,750		$	—

	Impairment of unproved properties	45,732			517			1,011

	Amortization of individually insignificant unproved properties	4,465			3,242			4,009

	Other	778			—			—

	Total continuing operations	163,532			52,509			5,020

	Discontinued operations:
	Impairment of proved properties	—			—			161,185

	Impairment of unproved properties	433			566			931

	Amortization of individually insignificant unproved properties	—			363			1,013

	Total discontinued operations	433			929			163,129

	Total impairment of crude oil and natural gas properties	$	163,965		$	53,438		$	168,149



	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 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties.

In 2012, we recognized an impairment charge of $161.2 million to write-down our Piceance Basin proved oil and natural gas properties to their estimated fair value. The fair value was based on estimated future cash flows from an unrelated third-party bid, a Level 3 input. The impairment charge was included in the consolidated statements of operations line item income from discontinued operations, net of tax.

Suspended Well Costs

The following table presents the capitalized exploratory well costs pending determination of proved reserves included in properties and equipment on the consolidated balance sheets:



	2013

	(in thousands)



Balance beginning of year, January 1,	$	19,567

Additions to capitalized exploratory well costs pending the determination of proved reserves	2,105

Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(21,672		)
Capitalized exploratory well costs charged to expense	—

Balance end of year, December 31,	$	—



Number of wells pending determination at December 31,	—



As of December 31, 2014, there were no suspended well costs or wells pending determination.

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2014
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,
		2014				2013				2012
		(in thousands)
	Current:
	Federal	$	(1,514	)		$	1,355			$	—

	State	966				199				(199		)

	Total current income taxes	(548		)		1,554				(199		)

	Deferred:
	Federal	(60,698		)		8,238				10,896

	State	(8,721		)		2,060				636

	Total deferred income taxes	(69,419		)		10,298				11,532

	Income tax benefit (expense) from continuing operations	$	(69,967	)		$	11,852			$	11,333



	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. As a result of these elections and deferral strategies, we generated federal and state net operating losses (“NOLs”) in 2012 and prior. 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 14, 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.

	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,
		2014			2013			2012

	Statutory tax rate	35	%		35	%		35	%
	State income tax, net	2.8			4			0.9

	Percentage depletion	(0.3	)		2.2			2

	Non-deductible compensation	0.7			(4.2	)		(0.5	)

	Other	1.3			(1.0	)		(0.5	)

	Effective tax rate	39.5	%		36	%		36.9	%


	The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2014 and 2013 are presented below:



		As of December 31,
		2014				2013
		(in thousands)
	Deferred tax assets:
	Net change in fair value of unsettled derivatives	$	—			$	6,205

	Deferred compensation	10,459				8,507

	Asset retirement obligations	28,051				11,630

	State NOL and tax credit carryforwards, net	3,761				5,182

Percentage depletion - carryforward	—				4,570

Alternative minimum tax - credit carryforward	2,906				3,165

Federal NOL carryforward	—				4,601

Settlement of class action litigation	12,259				—

Other	3,144				6,229

Deferred tax assets	60,580				50,089


Deferred tax liabilities:
Properties and equipment	130,155				120,746

Investment in PDCM	—				21,962

Net change in fair value of unsettled derivatives	113,007				—

Convertible debt	2,285				3,774

Total gross deferred tax liabilities	245,447				146,482

Net deferred tax liability	$	184,867			$	96,393


Classification in the consolidated balance sheets:
Deferred income tax assets	$	—			$	22,374

Deferred income tax liability - current	59,174				—

Deferred income tax liability - non-current	125,693				118,767

Net deferred tax liability	$	184,867			$	96,393



Deferred tax assets increased, primarily due to the addition of the deferred tax asset associated with asset retirement obligations and a legal accrual associated with the settlement of certain partnership-related class action litigation. These increases were partially offset by the utilization of our federal NOL and percentage depletion carryforwards and removal of the deferred tax asset associated with the unrealized tax loss for the fair value of unsettled derivatives.

Deferred tax liabilities for properties and equipment increased as a result of our continued use of statutory provisions for expensing and accelerated amortization of IDCs and accelerated tax depreciation. The increase from the use of these accelerated tax deductions was partially offset by the deferred tax asset for the impairment of some of our crude oil and natural gas properties. The sale of our entire 50% ownership interest in PDCM also resulted in a decrease to our deferred tax liability. In addition, the fair value of unsettled derivatives at December 31, 2014 resulted in an unrealized tax gain versus an unrealized loss at December 31, 2013.

As of December 31, 2014, we have state NOL carryforwards of $90.0 million that begin to expire in 2030 and state credit carryforwards of $1.3 million that begin to expire in 2023.

Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2014. The total amount of unrecognized tax benefits that would affect the effective tax rate decreased to zero in the current year due to the expiration of the statute of limitations. The statute of limitations for most of our state tax jurisdictions is open from 2010 forward.

In accordance with the CAP program, the IRS completed its “post filing review” of our 2012 and 2013 tax returns in January 2014 and 2015, respectively. We have been issued a “no change” letter for both of the reviewed tax years. 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 tax year and we have been invited and have accepted continued participation in the program for our 2015 tax year. Participation in the CAP program has enabled us to currently have no uncertain tax benefits associated with our federal tax return filings.

As of December 31, 2014, 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.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT

	Long-term debt consists of the following:



		As of December 31,
		2014			2013
		(in thousands)
	Senior notes:
	3.25% Convertible senior notes due 2016:
	Principal amount	$	115,000		$	115,000

	Unamortized discount	(6,077		)	(10,010		)
	3.25% Convertible senior notes due 2016, net of discount	108,923			104,990

	7.75% Senior notes due 2022	500,000			500,000

	Total senior notes	608,923			604,990

	Revolving credit facility	56,000			—

	Long-term debt	664,923			604,990


	PDCM credit facility	—			37,000

	PDCM second lien term loan	—			15,000

	PDCM long-term debt (included in liabilities held for sale - non-current)	—			52,000


	Total debt	$	664,923		$	656,990


	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 does not contain any restrictive 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.

	We may not redeem the Convertible Notes prior to their maturity. However, prior to November 15, 2015, holders of the Convertible Notes may convert upon specified events as defined in the governing indenture. The notes are convertible at any time thereafter 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, the Convertible Notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares.

	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, 2014, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the Convertible Notes of 1.4 years using an effective interest rate of 7.4%. For 2014, interest expense related to the indebtedness and the amortization of the discount was $3.7 million and $3.9 million, respectively, compared to $3.7 million each in 2013 and $3.7 million and $3.4 million, respectively, in 2012. As of December 31, 2014, notwithstanding the inability to convert, the principal amount exceeded the “if-converted” value of the Convertible Notes by approximately $3.1 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, 2015, we may redeem up to 35% of the outstanding 2022 Senior Notes with proceeds from certain equity offerings at a redemption price of 107.75% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as at least 65% of the aggregate principal amount of the notes issued on October 3, 2012 remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. 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, 2014, 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 twelve-month period.

	Credit Facility

	Revolving Credit Facility. In May 2013, we entered into a 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 expires in May 2018. 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. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our and our subsidiaries' 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. In September 2014, the semi-annual redetermination of our revolving credit facility's borrowing base was completed, resulting in an increase in the borrowing base from $450 million to $700 million. We have elected to maintain the aggregate commitment at $450 million. 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 $56.0 million on our revolving credit facility as of December 31, 2014 compared to no outstanding balance as of December 31, 2013. The weighted-average borrowing rate on our revolving credit facility, exclusive of the letter of credit noted below, was 4.1% per annum as of December 31, 2014.

	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 2018, 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, 2014, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next twelve-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 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, 2014, 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, which expires in September 2015, reduces the amount of available funds under our revolving credit facility by an equal amount. As of December 31, 2014, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $382.3 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.

PDCM

On October 14, 2014, we closed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party. The transaction included the repayment of the PDCM credit facility and Second Lien Credit Agreement ("Term Loan Agreement") by the buyer. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information.

ASSET_RETIREMENT_OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2014
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:


		2014			2013
		(in thousands)

	Balance at beginning of period, January 1, 2014	$	41,030		$	62,563

	Revisions in estimated cash flows	31,945			612

	Obligations incurred with development activities	1,170			2,389

	Accretion expense	3,455			4,747

	Obligations discharged with divestitures of properties and asset retirements	(3,745		)	(29,281		)
	Balance end of period, December 31, 2014	73,855			41,030

	Less: Liabilities held for sale (1)	—			(2,234		)

	Less: Current portion	(1,863		)	(1,158		)
	Long-term portion	$	71,992		$	37,638



	______________

	-1	Represents asset retirement obligations related to assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information.

	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
EMPLOYEE BENEFIT PLANS	Dec. 31, 2014
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 $3.9 million, $3.7 million and $3.4 million for 2014, 2013 and 2012, 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 2014, 2013 and 2012. As of December 31, 2014 and 2013, the liability related to this benefit was $1.5 million and $1.8 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, 2014 and 2013.

	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 2014, 2013 and 2012 related to this plan were immaterial. As of December 31, 2014 and 2013, the related liability of $0.7 million 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 immaterial as of December 31, 2014 and 2013.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2014
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 the required volumes are delivered or not.

	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	2015		2016		2017		2018		2019 and		Total		Expiration
										Through				Date
										Expiration

	Natural gas (MMcf)
	Appalachian Basin	7,117		7,136		7,117		7,117		25,803		54,290		August 31, 2022

	Utica Shale	2,737		2,745		2,737		2,737		12,549		23,505		July 22, 2023

	Total	9,854		9,881		9,854		9,854		38,352		77,795


	Crude oil (MBbls)
	Wattenberg Field	1,818		2,420		2,413		2,413		3,010		12,074		April 30, 2020


	Dollar commitment (in thousands)	$	14,481	$	17,624	$	17,158	$	16,327	$	30,361	$	95,951



	In September 2014, we entered into a long-term firm transportation agreement with White Cliffs Pipeline, LLC, to ship crude oil from southern Weld County, Colorado, to Cushing, Oklahoma. The primary term of the agreement is five years commencing on the first delivery of crude oil to the pipeline system, which we currently expect to begin in May 2015. The agreement includes minimum volume commitments as shown in the table above, with certain fees assessed for any shortfall. Concurrently, we entered into a crude oil purchase and sale agreement with Concord Energy, LLC, whereby we agreed to sell and Concord Energy, LLC agreed to purchase the entire minimum volume commitments under the long-term firm transportation agreement.

	On October 14, 2014, we closed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party. The transaction included the buyer's assumption of approximately 134,875 MMcf and $30.4 million of our Appalachian Basin firm transportation commitment. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information.

	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 is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges 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 an oral settlement agreement, subject to the contingencies noted below. That agreement was reduced to writing and signed in December 2014. Under this agreement the plaintiffs would receive a cash payment of $37.5 million, of which PDC would pay $31.5 million and insurers would pay $6 million. This all-cash settlement agreement is a different structure than the initial agreement in principle, which was structured as part up-front cash and part interests in future wells. The proposed all-cash settlement remains subject to the satisfaction of various conditions, including but not limited to final court approval; the hearing regarding final approval is currently scheduled for March 16, 2015. Preliminary approval by the court was received on December 30, 2014, and notice of the settlement was mailed to class members in mid-January 2015. Any class member elections to opt out of the settlement are due in February 2015. In late January 2015, PDC deposited the $37.5 million, including the $6 million paid directly to the Company by its insurers, into escrow, as provided in the agreement. As a result of this litigation, the Company accrued $31.5 million of expense in 2014, which is included in general and administrative expense in the consolidated statements of operations. As of December 31, 2014, the Company has accrued a total gross liability of $37.5 million related to this litigation, of which $31.5 million represents our expense and $6 million represents the portion our insurers would pay, which is our best estimate of the amount required to settle the case. The liability is included in other accrued expenses in the consolidated balance sheets. There is also a corresponding receivable due from our insurers of $6 million included in accounts receivable in the consolidated balance sheets, which was received from the insurers in January 2015.

	Under this settlement agreement, the class action would be dismissed with prejudice and all claims would be released. If the matter proceeds to trial, the plaintiffs have indicated that they will seek damages of approximately $175 million, plus pre-judgment interest. In such event, we continue to believe we would have good defenses to both the asserted claims and plaintiffs’ damage calculations.

	Partnership Liquidation Lawsuit

	In October 2014, following three days of court ordered mediation PDC entered into a written settlement term sheet pursuant to which PDC agreed to pay approximately $8.8 million in resolution of an adversary proceeding filed against PDC in June 2014 titled Eastern 1996D Limited Partnership, et al. v. PDC Energy, Inc. Adv. Pro. No. 14-03080 (the “Adversary Proceeding”) related to Jointly Administered bankruptcy Case No. 13-34773-HDH-11, currently pending in the United States Bankruptcy Court for the Northern District of Texas (the “Bankruptcy Court”). The bankruptcy case relates to 12 limited partnerships formed from1996 to 2002, for which PDC is the managing general partner. These partnerships filed bankruptcy in September 2013 to pursue an orderly liquidation of their assets and distribute the resulting proceeds to partners. The Adversary Proceeding primarily alleged claims for breach of fiduciary duty and breach of contract against PDC as managing general partner of the partnerships. In October 2014, the Bankruptcy Court approved the proposed disclosure statement in support of the debtors’ joint liquidating plan and the manner of solicitation of votes on such plan. The plan incorporated approval of the above proposed settlement. The plan, disclosure statement and ballot were mailed to the partners in November 2014. In December 2014 the Bankruptcy Court held a confirmation hearing and issued its final approval of the plan and settlement agreement. Thereafter, PDC deposited such monies into escrow. On December 31, 2014 the monies were released to the partnerships from escrow and distributed in accordance with the plan. In 2014, PDC recorded a litigation charge of $8.8 million related to this matter, included in general and administrative expense in the consolidated statements of operations.

	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 avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews 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, 2014 and December 31, 2013, we had accrued environmental liabilities in the amount of $0.8 million and $5.4 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, 2014 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 unknown past non-compliance with environmental laws will not be discovered on our properties.

	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, 2014:



		Year Ending December 31,
		2015		2016		2017		2018		2019		Thereafter		Total
		(in thousands)

	Minimum Lease Payments	$	2,517	$	2,285	$	2,099	$	1,908	$	1,937	$	2,091	$	12,837



	Operating lease expense for the years ended 2014, 2013 and 2012 was $7.0 million, $7.0 million and $6.1 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
COMMON STOCK	Dec. 31, 2014
COMMON STOCK [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block]	COMMON STOCK

	Sale of Equity Securities

	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.

	In May 2012, we completed a public offering of 6,500,000 shares of our common stock at an offering price of $26.50 per share. Net proceeds of the offering were approximately $164.5 million, after deducting underwriting discounts and commissions and offering expenses, of which $65,000 is included in common shares-par value and $164.4 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, 2014, 1,401,953 shares remain available for issuance pursuant to the 2010 Plan.

	2004 Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. We no longer issue awards pursuant to the 2004 Plan. As of December 31, 2014, all awards granted pursuant to the 2004 Plan had vested and are exercisable through April 19, 2020.

	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,
			2014				2013				2012
			(in thousands)

	Stock-based compensation expense		$	17,518			$	12,880			$	8,495
	Stock-based compensation expense		$	17,518			$	12,880			$	8,495
	Income tax benefit		(5,955		)		(4,697		)		(3,245		)
	Net stock-based compensation expense		$	11,563			$	8,183			$	5,250
	Net stock-based compensation expense		$	11,563			$	8,183			$	5,250


	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 2014, the Compensation Committee awarded 88,248 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,
		2014				2013				2012

	Expected term of award	6 years				6 years				6 years
	Expected term of award	6 years				6 years				6 years
	Risk-free interest rate	2.1		%		1		%		1.1		%
	Expected volatility	65.6		%		65.5		%		64.3		%
	Weighted-average grant date fair value per share	$	29.96			$	21.96			$	17.61
	Weighted-average grant date fair value per share	$	29.96			$	21.96			$	17.61

	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:



		Year Ended December 31,
		2014													2013										2012
		Number of			Weighted-Average				Average Remaining Contractual			Aggregate Intrinsic			Number of			Weighted-Average			Aggregate Intrinsic				Number of		Weighted-Average			Aggregate Intrinsic
		SARs			Exercise				Term (in years)			Value (in thousands)			SARs			Exercise			Value (in thousands)				SARs		Exercise			Value (in thousands)
					Price													Price									Price
	Outstanding beginning of year, January 1,	190,763			$	33.77			8.2			$	3,711		118,832			$	30.8		$	486			50,471		$	31.61		$	341
	Outstanding beginning of year, January 1,	190,763			$	33.77			8.2			$	3,711		118,832			$	30.8		$	486			50,471		$	31.61		$	341
	Awarded	88,248			49.57				—			—			87,078			37.18			—				68,361		30.19			—
	Awarded	88,248			49.57				—			—			87,078			37.18			—				68,361		30.19			—
	Exercised	—			—				—			—			(15,147	)		30.06			425				—		—			—
	Exercised	—			—				—			—			(15,147	)		30.06			425				—		—			—
	Outstanding at December 31,	279,011			38.77				7.8			1,472			190,763			33.77			3,711				118,832		30.8			486
	Outstanding at December 31,	279,011			38.77				7.8			1,472			190,763			33.77			3,711				118,832		30.8			486
Exercisable at December 31,	139,334			36.27				7.3			982			51,922			29.97			1,207				27,458		28.84			187
Exercisable at December 31,	139,334			36.27				7.3			982			51,922			29.97			1,207				27,458		28.84			187

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, 2014, was $2.3 million. The cost is expected to be recognized over a weighted-average period of 1.7 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 or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed.

In January 2014, the Compensation Committee awarded a total of 104,467 time-based restricted shares to our executive officers that vest ratably over the three year period ending on January 16, 2017.

The following table presents the changes in non-vested time-based awards during 2014:


	Shares			Weighted-Average
				Grant-Date
				Fair Value

Non-vested at December 31, 2013	651,781			$	36.36
Non-vested at December 31, 2013	651,781			$	36.36
Granted	291,370			56.45
Granted	291,370			56.45
Vested	(328,071	)		36.26
Vested	(328,071	)		36.26
Forfeited	(50,748	)		45.04
Forfeited	(50,748	)		45.04
Non-vested at December 31, 2014	564,332			46.02
Non-vested at December 31, 2014	564,332			46.02




	As of/Year Ended December 31,
	2014				2013				2012
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	18,278			$	13,640			$	5,950
Total intrinsic value of time-based awards vested	$	18,278			$	13,640			$	5,950
Total intrinsic value of time-based awards non-vested	23,290				34,688				21,470
Total intrinsic value of time-based awards non-vested	23,290				34,688				21,470
Market price per common share as of December 31,	41.27				53.22				33.21
Market price per common share as of December 31,	41.27				53.22				33.21
Weighted-average grant date fair value per share	56.45				45.53				26.59
Weighted-average grant date fair value per share	56.45				45.53				26.59

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, 2014 was $17.0 million. This cost is expected to be recognized over a weighted-average period of 1.8 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 five 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 2014, the Compensation Committee awarded a total of 42,151 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 set group of 15 peer companies. The shares are measured over a three-year period ending on December 31, 2016 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,
		2014				2013

Expected term of award		3 years				3 years
Expected term of award		3 years				3 years
Risk-free interest rate		0.8		%		0.4		%
Expected volatility		55.2		%		56.6		%
Weighted-average grant date fair value per share		$	56.87			$	49.04
Weighted-average grant date fair value per share		$	56.87			$	49.04

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 2014:


		Shares			Weighted-Average
					Grant-Date
					Fair Value per Share

Non-vested at December 31, 2013		72,111			$	43.75
Non-vested at December 31, 2013		72,111			$	43.75
Granted		42,151			56.87
Granted		42,151			56.87
Vested		(30,541	)		36.54
Vested		(30,541	)		36.54
Non-vested at December 31, 2014		83,721			52.98
Non-vested at December 31, 2014		83,721			52.98




	As of/Year Ended December 31,
	2014				2013				2012
	(in thousands, except per share data)

Total intrinsic value of market-based awards vested	$	1,260			$	724			$	—
Total intrinsic value of market-based awards vested	$	1,260			$	724			$	—
Total intrinsic value of market-based awards non-vested	3,455				3,838				1,352
Total intrinsic value of market-based awards non-vested	3,455				3,838				1,352
Market price per common share as of December 31,	41.27				53.22				33.21
Market price per common share as of December 31,	41.27				53.22				33.21
Weighted-average grant date fair value per share	56.87				49.04				36.54
Weighted-average grant date fair value per share	56.87				49.04				36.54

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, 2014 was $2.3 million. This cost is expected to be recognized over a weighted-average period of 1.7 years.

Stock Option Awards

We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock option awards since 2006. As of December 31, 2014, all compensation cost related to stock options has been fully recognized in our consolidated statements of operations.

The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial:



	Year Ended December 31,
	2014													2013						2012
	Number of			Weighted-Average				Weighted- Average			Aggregate Intrinsic			Number of			Weighted-Average			Number of			Weighted-Average
	Shares			Exercise				Remaining			Value (in thousands)			Shares			Exercise			Shares			Exercise
	Underlying			Price				Contractual						Underlying			Price			Underlying			Price
	Options			Per Share				Term (in years)						Options			Per Share			Options			Per Share
Outstanding beginning of year, January 1,	3,523			$	44.95			2.2			$	—		6,973			$	41.09		6,973			$	41.09
Outstanding beginning of year, January 1,	3,523			$	44.95			2.2			$	—		6,973			$	41.09		6,973			$	41.09
Exercised	—			—				—			—			(3,450	)		37.15			—			—
Exercised	—			—				—			—			(3,450	)		37.15			—			—
Outstanding end of year, December 31,	3,523			44.95				1.2			—			3,523			44.95			6,973			41.09
Outstanding end of year, December 31,	3,523			44.95				1.2			—			3,523			44.95			6,973			41.09
Exercisable at December 31,	3,523			44.95				1.2			—			3,523			44.95			6,973			41.09
Exercisable at December 31,	3,523			44.95				1.2			—			3,523			44.95			6,973			41.09

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 2004 Plan are retired, while those issued pursuant to the 2010 Plan are reissued to service awards. For shares that are retired, we first charge any excess of cost over the par value to APIC to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. 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, 2014, we acquired 97,646 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 703 shares were retired and 83,208 shares reissued and 13,735 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, 2014, no preferred shares had been issued.

EARNINGS_PER_SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2014
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,
		2014	2013	2012
		(in thousands)

	Weighted-average common shares outstanding - basic	35,784	32,426	27,677

	Dilutive effect of:
	Restricted stock	279	—	—

	Stock options	1	—	—

	SARs	45	—	—

	Non-employee director deferred compensation	5	—	—

	Convertible notes	564	—	—

	Weighted-average common shares and equivalents outstanding - diluted	36,678	32,426	27,677



	For 2013 and 2012, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same as 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,
		2014	2013	2012
		(in thousands)

	Weighted-average common share equivalents excluded from diluted earnings
	per share due to their anti-dilutive effect:
	Restricted stock	8	823	694

	SARs	26	72	116

	Stock options	—	7	7

	Non-employee director deferred compensation	—	4	3

	Convertible notes	—	518	—

	Total anti-dilutive common share equivalents	34	1,424	820



	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 dilutive 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 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. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2013 as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2012 as the conversion price was greater than the average market price of our common stock during the period.

ASSETS_HELD_FOR_SALE_DIVESTITU

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS

	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 were or are expected to be sold, net of liabilities, that were assumed by the purchaser. 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 balance sheet data related to net assets held for sale:



	Consolidated balance sheet		As of December 31, 2014				As of December 31, 2013

	Assets
	Current assets
	Cash and cash equivalents		$	—			$	601

	Other current assets		—				7,060

	Assets held for sale - current		—				7,661


	Non-current assets
	Properties and equipment, net		2,874				175,244

	Other assets		—				6,892

	Assets held for sale - non-current		2,874				182,136


	Liabilities
	Liabilities held for sale - current		—				12,069


	Non-current liabilities
	Long-term debt		—				52,000

	Asset retirement obligation		—				2,234

	Other liabilities		—				1,681

	Liabilities held for sale - non-current		—				55,915


	Net Assets		$	2,874			$	121,813


	Assets held for sale as of December 31, 2014 represents the carrying value of approximately 12 acres of land located adjacent to a regional office. Assets held for sale as of December 31, 2013 represents our proportionate share of PDCM's net assets and the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters.



	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			2012
			(in thousands)
	Revenues
	Crude oil, natural gas and NGLs sales		$	24,149			$	39,001		$	46,793

	Sales from natural gas marketing		—				2,825			1,708

	Commodity price risk management gain (loss), net		(1,085		)		14			3,060

	Well operations, pipeline income and other		48				922			1,926

Total revenues		23,112				42,762			53,487


Costs, expenses and other
Production costs		7,120				16,515			27,770

Cost of natural gas marketing		—				2,673			1,529

Impairment of crude oil and natural gas properties		433				929			163,129

Depreciation, depletion and amortization		9,128				13,894			55,768

Other		3,445				7,266			8,791

(Gain) loss on sale of properties and equipment		(76,479		)		1,700			(24,090		)

Total costs, expenses and other		(56,353		)		42,977			232,897


Interest expense		(2,222		)		(1,755		)	(782		)
Interest income		194				10			1

Income (loss) from discontinued operations		77,437				(1,960		)	(180,191		)

Provision for income taxes		(29,263		)		770			68,834

Income (loss) from discontinued operations, net of tax		$	48,174			$	(1,190	)	$	(111,357	)



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			2012
		(in thousands)
Cash flows from investing activities:
Capital expenditures		$	(17,253	)		$	(45,277	)	$	(25,530	)

Significant non-cash investing items:
Change in accounts payable related to purchases of properties and equipment		(5,727		)		(4,738		)	(3,592		)


Appalachian Basin. In December 2013, we divested our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties previously owned directly by us, as well as through our proportionate share of PDCM, for aggregate consideration of approximately $20.6 million, of which our share of the proceeds was approximately $5.1 million. We received our proportionate share of cash proceeds and a note receivable. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services was released and novated to the buyer.

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.

Piceance Basin and NECO. In February 2013, we entered into a purchase and sale agreement pursuant to which we agreed to sell to an unrelated third-party our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Additionally, certain firm transportation commitments and natural gas hedging positions were assumed by the buyer. In June 2013, this divestiture was completed with total consideration of approximately $177.6 million, with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million. The proceeds from the asset divestiture were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. Following the sale, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations.

ACQUISITIONS

ACQUISITIONS	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	ACQUISITIONS

	The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of crude oil and natural gas properties during 2012:



		Year Ended December 31, 2012
		(in thousands)

	Total acquisition cost	$	304,643


	Recognized amounts of identifiable assets acquired and liabilities assumed:
	Assets acquired:
	Crude oil and natural gas properties - proved	$	180,696

	Crude oil and natural gas properties - unproved	151,428

	Other assets	3,631

	Total assets acquired	335,755

	Liabilities assumed:
	Asset retirement obligation	14,833

	Other accrued expenses	9,574

	Other liabilities	6,705

	Total liabilities assumed	31,112

	Total identifiable net assets acquired	$	304,643



	The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are sensitive and subject to change.

	Merit Acquisition. In June 2012, we completed the acquisition of certain Wattenberg Field oil and natural gas properties, leasehold mineral interests and related assets located in Weld, Adams and Boulder Counties, Colorado from affiliates of Merit Energy. The aggregate purchase price of these properties was approximately $304.6 million. We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit facility.

	This acquisition was accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.

	Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 2012 closing date. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 assuming the Merit Acquisition had been completed as of January 1, 2012, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results.


		Year Ended December 31, 2012
		(in thousands, except per share amounts)

	Total revenues	$	370,488

	Total costs, expenses and other	521,178

	Net income (loss)	$	(119,343	)

	Earnings per share:
	Basic	$	(4.31	)
	Diluted	$	(4.31	)

TRANSACTIONS_WITH_AFFILIATES_A

TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES	12 Months Ended
TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES	Dec. 31, 2014
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 and $0.5 million in 2013 and 2012, respectively, related to the marketing of natural gas on behalf of our affiliated partnerships and $23.2 million, $18.1 million and $10.9 million in 2014, 2013 and 2012, respectively, related to the marketing of natural gas on behalf of PDCM.

	Amounts due from/to affiliates primarily relate to certain well operating and administrative costs incurred on behalf of our affiliated partnerships and will be recouped through future partnership revenue distributions. Prior to October 2014, amounts due from/to affiliates also included amounts billed for certain well operating and administrative services provided to PDCM. Amounts billed to PDCM for these services were $5.7 million, $14.5 million and $12.1 million in 2014, 2013 and 2012, 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 compared to $4.6 million as of December 31, 2013.

BUSINESS_SEGMENTS

BUSINESS SEGMENTS	12 Months Ended
	Dec. 31, 2014
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 $188.5 million, $111.6 million and $86.3 million in 2014, 2013 and 2012, 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:



		2014			2013			2012
		(in thousands)
	Year Ended December 31,
	Segment revenues:
	Oil and gas exploration and production	$	784,636		$	322,878		$	261,765

	Gas marketing	71,571			69,787			45,371

	Total revenues	$	856,207		$	392,665		$	307,136


	Segment income (loss) before income taxes:
	Oil and gas exploration and production	$	344,149		$	81,913		$	101,324

	Gas marketing	(445		)	(297		)	348

	Unallocated	(166,476		)	(114,579		)	(132,360		)
	Income (loss) before income taxes	$	177,228		$	(32,963	)	$	(30,688	)


	Expenditures for segment long-lived assets:
	Oil and gas exploration and production	$	623,912		$	403,227		$	656,443

	Unallocated	4,680			1,379			3,509

	Total	$	628,592		$	404,606		$	659,952


	As of December 31,
	Segment assets:
	Oil and gas exploration and production	$	2,254,751		$	1,751,106

	Gas marketing	6,979			20,342

	Unallocated	75,984			63,958

	Assets held for sale	2,874			189,797

	Total assets	$	2,340,588		$	2,025,203

SUPPLEMENTAL_INFORMATION_NATUR

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES	12 Months Ended
	Dec. 31, 2014
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, condensate and NGL reserves. As of December 31, 2014, 2013 and 2012, all of our estimates of proved reserves were based on reserve reports prepared by Ryder Scott. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

	Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of crude oil, natural gas and NGLs expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities.

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



			Price Used to Estimate Reserves

	As of December 31,		Crude Oil				Natural Gas				NGLs
			(per Bbl)				(per Mcf)				(per Bbl)

	2014		$	84.65			$	3.92			$	32.27

	2013		82.18				3.22				29.92

	2012		87.51				2.35				28.02








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



		Crude Oil, Condensate (MBbls)			Natural Gas			NGLs			Total
					(MMcf)			(MBbls)			(MBoe)
	Proved Reserves:
	Proved reserves, January 1, 2012 (1)	37,636			672,145			19,588			169,248

	Revisions of previous estimates	(6,729	)		(289,436	)		(3,671	)		(58,639	)
	Extensions, discoveries and other additions	27,482			172,933			11,637			67,941

	Purchases of reserves	10,801			87,212			8,084			33,420

	Dispositions	(7,854	)		(6,406	)		(1,970	)		(10,891	)
	Production	(2,026	)		(32,410	)		(841	)		(8,269	)
	Proved reserves, December 31, 2012 (2)	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	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 (3)	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	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




Proved Developed Reserves, as of:
January 1, 2012 (1)	16,910			299,369			11,753			78,558

December 31, 2012 (2)	20,412			281,925			14,353			81,753

December 31, 2013 (3)	23,997			220,387			14,825			75,553

31-Dec-14	26,798			186,633			17,002			74,905

Proved Undeveloped Reserves, as of:

January 1, 2012 (1)	20,726			372,776			7,835			90,690

December 31, 2012 (2)	38,898			322,113			18,474			111,058

December 31, 2013 (3)	69,833			519,253			33,846			190,221

31-Dec-14	73,717			350,339			43,117			175,224


__________

-1	Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian assets. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively.

-2	Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, 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.

-3	Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 14, 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, 2012	78,558			90,690			169,248

Undeveloped reserves converted to developed	7,655			(7,655	)		—

Revisions of previous estimates	(18,318	)		(40,321	)		(58,639	)
Extensions, discoveries and other additions	11,298			56,643			67,941

Purchases of reserves	13,542			19,878			33,420

Dispositions	(2,713	)		(8,178	)		(10,891	)
Production	(8,269	)		—			(8,269	)

Ending proved reserves, December 31, 2012	81,753			111,057			192,810

Undeveloped reserves converted to developed	3,212			(3,212	)		—

Revisions of previous estimates	(6,751	)		(39,729	)		(46,480	)
Extensions, discoveries and other additions	19,830			122,105			141,935

Purchases of reserves	1,043			—			1,043

Dispositions	(16,104	)		—			(16,104	)

Production	(7,430	)		—			(7,430	)

Ending proved reserves, December 31, 2013	75,553			190,221			265,774

Undeveloped reserves converted to developed	12,730			(12,730	)		—

Revisions of previous estimates	(22,827	)		(41,998	)		(64,825	)
Extensions, discoveries and other additions	27,957			70,072			98,029

Purchases of reserves	17			—			17

Dispositions	(9,231	)		(30,341	)		(39,572	)
Production	(9,294	)		—			(9,294	)

Ending proved reserves, December 31, 2014	74,905			175,224			250,129



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 and 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, 8 MMBoe of Utica Shale PUDs that are no longer in our drilling plans and 2 MMBoe due to various other factors. Discoveries and extensions resulted in an increase of approximately 98 MMBoe in 2014, of which approximately 96 MMBoe was added in the Wattenberg Field, primarily related to Niobrara and Codell projects, and approximately 2 MMBoe was added in the Utica Shale. The reserve increases in the Wattenberg Field are primarily due to the addition of approximately 16 MMBoe of previously unbooked locations which were developed in the current year, 78 MMBoe due to new proved undeveloped reserves as a result of adjustments in well spacing in the Wattenberg Field and our development plan and 2 MMBoe due to various other factors. We acquired minimal proved reserves. We divested a total of 40 MMBoe in 2014, primarily from our Marcellus Shale assets. Based on the economic conditions on December 31, 2014, our approved development plan provides 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. This resulted in a PUD conversion rate of approximately 7% and allowed us to add considerable PUD reserves to the 2014 reserve report as noted above. Because we expect to continue to drill primarily proven downspaced Wattenberg Field locations in 2015, our PUD conversion rate is expected to be approximately 16%. The balance of the locations are scheduled to be drilled over the remaining four years with total PUD conversion rates of 27% in 2016, 22% in 2017, 19% in 2018 and 16% in 2019. This level of capital spending is consistent with the most recent years and our outlook for future activity.

2013 Activity. Overall, our proved reserves increased by 73 MMBoe as of December 31, 2013 as compared to December 31, 2012. In 2013, 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 adjustments in previous PUD well spacing plans in the Wattenberg Field and the Marcellus Shale (which were offset by replacements in the extension category), 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 are no longer in our core drilling area. This was partially offset by an increase of 1 MMBoe due to higher gas pricing and lower operating costs in the vertical Wattenberg Field wells and horizontal Marcellus Shale wells, an increase of approximately 3 MMBoe due to non-acquisition interest adjustments, approximately 2 MMBoe due to asset performance and approximately 2 MMBoe due to production from wells that were either uneconomic, added or divested in the current year. Discoveries and extensions of approximately 142 MMBoe in 2013 are due to the addition of approximately 17 MMBoe of proved developed reserves from non-PUD drilling and the addition of approximately 125 MMBoe of new proved undeveloped reserves including 32 MMBoe due to adjustments in well spacing in the Wattenberg Field and the Marcellus Shale. Approximately 18 MMBoe was added in the Marcellus Shale, approximately 14 MMBoe was added in the Utica Shale and approximately 110 MMBoe was added in the Wattenberg Field, mostly related to the Niobrara and Codell formations. We acquired approximately 1 MMBoe of proved reserves due to an acquisition in the Appalachian-Marcellus Shale area and the acquisition of non-affiliated investor partner interests in shallow Upper Devonian wells. We divested a total of 16 MMBoe in 2013, primarily our Piceance Basin, NECO and shallow Upper Devonian (non-Marcellus Shale) assets. Based on the economic conditions on December 31, 2013, our approved development plan provides 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.

2012 Activity. In 2012, we recorded a downward revision of our previous estimate of proved reserves of approximately 59 MMBoe. The revision was primarily due to a decrease of approximately 40 MMBoe due to lower gas pricing, mostly related to the Piceance Basin, approximately 1 MMBoe due to increased operating costs, approximately 8 MMBoe due to adjustments for geological reasons and approximately 13 MMBoe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 0.5 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe due to asset performance. Discoveries and extensions of approximately 68 MMBoe in 2012 are due to the drilling of 44 gross horizontal wells and the addition of new proved undeveloped reserves. Approximately 10 MMBoe were added in the Marcellus Shale and approximately 59 MMBoe were added in the Wattenberg Field, mostly related to the Niobrara formation. We acquired approximately 33 MMBoe of proved reserves due to an acquisition in the Wattenberg Field. We divested a total of 11 MMBoe in 2012, primarily our core Permian Basin assets. Based on the economic conditions on December 31, 2012, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Based on our decision to drill predominantly horizontal wells in 2012, our drilling program focused on locations that were not included in proved undeveloped reserves in the December 2011 reserve report. By focusing on non-PUD drilling locations in 2012, we were able to add considerable PUD reserves in the 2012 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,

	2014				2013				2012

	(in thousands)

Revenue:

Crude oil, natural gas and NGLs sales	$	495,562			$	379,796			$	274,783

Commodity price risk management gain, net	309,219				(23,905		)		32,339

	804,781				355,891				307,122

Expenses:
Production costs	90,744				81,365				77,537

Exploration expense	948				7,071				22,605

Impairment of proved crude oil and natural gas properties	163,965				53,438				162,287

Depreciation, depletion, and amortization	201,656				124,202				146,879

Accretion of asset retirement obligations	3,455				4,747				4,060

(Gain) loss on sale of properties and equipment	(75,972		)		3,722				(24,273		)

	384,796				274,545				389,095

Results of operations for crude oil and natural gas producing	419,985				81,346				(81,973		)
activities before provision for income taxes


Provision for income taxes	(163,647		)		(29,400		)		31,163



Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	256,338			$	51,946			$	(50,810	)



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,
	2014				2013				2012
	(in thousands)
Acquisition of properties: (1)
Proved properties	$	11,973			$	28,698			$	105,303

Unproved properties	45,999				3,390				276,225

Development costs (2)	590,855				332,250				233,144

Exploration costs: (3)
Exploratory drilling	—				58,988				18,803

Geological and geophysical	1				752				1,925

Total costs incurred	$	648,828			$	424,078			$	635,400


__________

-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, 2014, 2013 and 2012, $125.2 million, $40.1 million and $62.0 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,
	2014				2013
	(in thousands)

Proved crude oil and natural gas properties	$	2,267,165			$	1,677,271

Unproved crude oil and natural gas properties	188,206				253,463

Uncompleted wells, equipment and facilities	137,134				40,745

Capitalized costs	2,592,505				1,971,479

Less accumulated DD&A	(808,431		)		(507,510		)
Capitalized costs, net	$	1,784,074			$	1,463,969



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,
	2014				2013				2012
	(in thousands)

Future estimated cash flows	$	12,550,515			$	11,550,917			$	7,529,292

Future estimated production costs	(2,816,776		)		(2,329,836		)		(1,690,453		)
Future estimated development costs	(2,458,790		)		(2,778,148		)		(1,852,177		)
Future estimated income tax expense	(2,336,510		)		(2,119,615		)		(1,230,294		)
Future net cash flows	4,938,439				4,323,318				2,756,368

10% annual discount for estimated timing of cash flows	(2,631,974		)		(2,541,155		)		(1,587,871		)
Standardized measure of discounted future estimated net cash flows	$	2,306,465			$	1,782,163			$	1,168,497



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



	Year Ended December 31,
	2014				2013				2012
	(in thousands)

Sales of crude oil, natural gas and NGLs production, net of production costs	$	(387,789	)		$	(286,021	)		$	(194,346	)
Net changes in prices and production costs (1)	129,213				89,527				95,501

Extensions, discoveries, and improved recovery, less related costs (2)	1,444,581				1,529,006				632,781

Sales of reserves (3)	(402,595		)		(142,724		)		(86,902		)
Purchases of reserves (4)	238				10,610				296,208

Development costs incurred during the period	161,404				46,366				69,198

Revisions of previous quantity estimates (5)	(654,318		)		(397,738		)		(452,775		)
Changes in estimated income taxes (6)	(221,874		)		(381,369		)		(131,256		)
Net changes in future development costs	46,499				(40,707		)		(3,979		)

Accretion of discount	270,389				142,040				124,105

Timing and other	138,554				44,676				(121,247		)

Total	$	524,302			$	613,666			$	227,288


__________

-1	Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to $37.78 as compared to $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. Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $30.82 from $30.28 in our 2012 report due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which increased our liquids as a percentage of proved reserves.

-2	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. The 142% increase in 2013 as compared to 2012 is primarily due to the addition of PUDs in the Utica Shale and our continued focus on our Wattenberg Field drilling program. Our increased PUD count in the Wattenberg Field is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report.

-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. The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013.

-4	The decrease in purchases of reserves in 2014 and 2013 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 2014 as compared to 2013 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule.

-6	The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38%, 38% and 38.2% for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital.

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_QUART

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL INFORMATION - UNAUDITED

	Quarterly financial data for the years ended December 31, 2014 and 2013 is presented below. 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.



		2014
		Quarter Ended
		31-Mar				30-Jun				30-Sep				31-Dec				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:
	Production costs	18,083				23,774				22,754				19,013				83,624

	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	910				848				1,863				159,911				163,532

	General and administrative expense	22,484				39,440				34,625				19,310				115,859

	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

	Income (loss) from discontinued operations	(0.02		)		0.03				—				1.33				1.34

	Net income (loss)	$	(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)	$	(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











	2013
	Quarter Ended
	31-Mar				30-Jun				30-Sep				31-Dec				Year Ended
	(in thousands, except per share data)
Revenues:
Crude oil, natural gas and NGLs sales	$	75,950			$	73,695			$	77,340			$	113,810			$	340,795

Sales from natural gas marketing	13,670				18,079				16,946				21,092				69,787

Commodity price risk management gain (loss), net	(19,765		)		21,828				(24,138		)		(1,844		)		(23,919		)

Well operations, pipeline income and other	1,060				954				1,667				2,321				6,002

Total revenues	70,915				114,556				71,815				135,379				392,665

Costs, expenses and other:
Production costs	14,381				14,274				17,036				19,159				64,850

Cost of natural gas marketing	13,736				18,065				17,127				21,156				70,084

Exploration expense	1,540				1,266				1,841				1,687				6,334

Impairment of crude oil and natural gas properties	46,260				1,298				4,236				715				52,509

General and administrative expense	14,037				14,849				15,052				16,018				59,956

Depreciation, depletion and amortization	25,431				25,488				26,957				37,748				115,624

Accretion of asset retirement obligations	1,143				1,167				1,181				1,075				4,566

(Gain) loss on sale of properties and equipment	(30		)		(1		)		(100		)		2,153				2,022

Total costs, expenses and other	116,498				76,406				83,330				99,711				375,945

Income (loss) from operations	(45,583		)		38,150				(11,515		)		35,668				16,720

Interest expense	(13,088		)		(12,838		)		(11,957		)		(12,260		)		(50,143		)
Interest income	—				3				130				327				460

Income (loss) from continuing operations before income taxes	(58,671		)		25,315				(23,342		)		23,735				(32,963		)

Provision for income taxes	20,798				(9,444		)		9,435				(8,937		)		11,852

Income (loss) from continuing operations	(37,873		)		15,871				(13,907		)		14,798				(21,111		)

Income (loss) from discontinued operations, net of tax	(1,545		)		4,047				(2,093		)		(1,599		)		(1,190		)

Net income (loss)	$	(39,418	)		$	19,918			$	(16,000	)		$	13,199			$	(22,301	)


Earnings per share:
Basic
Income (loss) from continuing operations	$	(1.25	)		$	0.53			$	(0.42	)		$	0.42			$	(0.65	)

Income (loss) from discontinued operations	(0.05		)		0.13				(0.06		)		(0.04		)		(0.04		)

Net income (loss) attributable to shareholders	$	(1.30	)		$	0.66			$	(0.48	)		$	0.38			$	(0.69	)

Diluted
Income (loss) from continuing operations	$	(1.25	)		$	0.51			$	(0.42	)		$	0.4			$	(0.65	)

Income (loss) from discontinued operations	(0.05		)		0.13				(0.06		)		(0.04		)		(0.04		)

Net income (loss) attributable to shareholders	$	(1.30	)		$	0.64			$	(0.48	)		$	0.36			$	(0.69	)


Weighted-average common shares outstanding
Basic	30,270				30,332				33,413				35,620				32,426

Diluted	30,270				31,014				33,413				36,836				32,426

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Consolidation, Policy [Policy Text Block]	The consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of PDCM (until the fourth quarter of 2014) and our affiliated partnerships. As of December 31, 2014, 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]	Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are attributable to reporting as discontinued operations the results of operations related to PDCM's Marcellus Shale assets and reporting as held for sale our proportionate share of PDCM's Marcellus Shale assets and liabilities, as well as a parcel of land. 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 to production costs. 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. We currently use the "net-back" method of accounting for crude oil, natural gas and NGLs production from the Wattenberg Field and 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. Natural gas and NGLs sales related to production from the Utica Shale are recognized based on gross prices as the purchasers do not provide transportation, gathering or processing services and we recognize expenses relating to those services as production costs.

	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.
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.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Adopted Accounting Standard. On January 1, 2014, we adopted changes issued by the Financial Accounting Standards Board ("FASB") regarding the accounting for income taxes. The change provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. Adoption of these changes had no impact on the consolidated financial statements.

	In April 2014, the FASB issued changes related to the criteria for determining which disposals can be presented as discontinued operations and modified related disclosure requirements. Under the new pronouncement, a discontinued operation is defined as a component of an entity that either has been disposed of or is classified as held for sale and represents a strategic shift that has a major effect on the entity's operations and financial results. These changes were required to be applied prospectively for new disposals or components of an entity classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. On July 1, 2014, we elected to early adopt the new pronouncement.

	Recently Issued Accounting Standard. In May 2014, the FASB and the International Accounting Standards Board ("IASB") 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: (a) identify the contract with the customer, (b) identify the separate performance obligations in the contract, (c) determine the transaction price, (d) allocate the transaction price to separate performance obligations and (e) recognize revenue when (or as) each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and can be adopted under the full retrospective method or simplified transition method. Early adoption is not permitted. We plan to adopt the revenue standard beginning January 1, 2017 and are currently evaluating the impact these changes will 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. We are currently evaluating the impact these changes will have on our consolidated financial statements.

	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 are currently evaluating the impact these changes will have 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. The adoption of this guidance is not expected to have a significant impact on our consolidated financial statements.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
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. Total impairments to other property and equipment was $0.8 million in 2014. There were no impairments to other property and equipment in 2013 or 2012.

	The following table presents the estimated useful lives of our other property and equipment:



	Pipelines and related facilities	10 - 17 years
	Transportation and other equipment	3 - 20 years
	Buildings	20 - 30 years

FAIR_VALUE_MEASUREMENTS_AND_DI1

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014												2013
		Significant Other				Significant				Total				Significant Other			Significant		Total
		Observable				Unobservable								Observable			Unobservable
		Inputs				Inputs								Inputs			Inputs
		(Level 2)				(Level 3)								(Level 2)			(Level 3)
		(in thousands)
	Assets:
	Commodity-based derivative contracts	$	237,939			$	62,356			$	300,295			$	3,852		$	2,098	$	5,950

	Basis protection derivative contracts	19				—				19				74			—		74

	Total assets	237,958				62,356				300,314				3,926			2,098		6,024

	Liabilities:
	Commodity-based derivative contracts	742				—				742				16,539			987		17,526

	Basis protection derivative contracts	25				—				25				5			—		5

	Total liabilities	767				—				767				16,544			987		17,531

	Net asset (liability)	$	237,191			$	62,356			$	299,547			$	(12,618	)	$	1,111	$	(11,507	)


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:



			2014				2013				2012

			(in thousands)



	Fair value, net asset, beginning of period		$	1,111			$	13,610			$	22,107

	Changes in fair value included in statement of operations line item:
	Commodity price risk management gain (loss), net		62,003				(1,748		)		7,517

	Sales from natural gas marketing		(22		)		13				63

	Changes in fair value included in balance sheet line item (1):
	Accounts payable affiliates		—				—				(319		)

	Settlements included in statement of operations line items:
	Commodity price risk management gain (loss), net		(737		)		(6,361		)		(15,644		)
	Sales from natural gas marketing		1				(37		)		(114		)

	Loss from discontinued operations, net of tax		—				(4,366		)		—

	Fair value, net asset end of period		$	62,356			$	1,111			$	13,610



	Net change in fair value of unsettled derivatives included in statement of operations line item:
	Commodity price risk management gain (loss), net		$	15,632			$	(2,731	)		$	3,665

	Sales from natural gas marketing		3				4				1

	Total		$	15,635			$	(2,727	)		$	3,666



	__________

	-1	Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.

DERIVATIVE_FINANCIAL_INSTRUMEN1

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:



	Derivative instruments:			Balance sheet line item	2014			2013
					(in thousands)
	Derivative assets:	Current
		Commodity contracts
		Related to crude oil and natural gas sales		Fair value of derivatives	$	186,886		$	1,086

		Related to natural gas marketing		Fair value of derivatives	590			361

		Basis protection contracts
		Related to crude oil and natural gas sales		Fair value of derivatives	19			74

					187,495			1,521

		Non-current
		Commodity contracts
		Related to crude oil and natural gas sales		Fair value of derivatives	112,599			4,225

		Related to natural gas marketing		Fair value of derivatives	220			278

					112,819			4,503

	Total derivative assets				$	300,314		$	6,024


	Derivative liabilities:	Current
		Commodity contracts
		Related to crude oil and natural gas sales		Fair value of derivatives	$	—		$	14,437

		Related to natural gas marketing		Fair value of derivatives	545			247

		Basis protection contracts
		Related to crude oil and natural gas sales		Fair value of derivatives	25			—

		Related to natural gas marketing		Fair value of derivatives	—			5

					570			14,689

		Non-current
		Commodity contracts
		Related to crude oil and natural gas sales		Fair value of derivatives	—			2,609

		Related to natural gas marketing		Fair value of derivatives	197			233

					197			2,842

	Total derivative liabilities				$	767		$	17,531




	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		2014			2013			2012


	Commodity price risk management gain (loss), net
Net settlements		$	(837	)	$	11,177		$	43,591

Net change in fair value of unsettled derivatives		311,141			(35,096		)	(14,312		)

Total commodity price risk management gain (loss), net		$	310,304		$	(23,919	)	$	29,279

Sales from natural gas marketing
Net settlements		$	(208	)	$	446		$	2,170

Net change in fair value of unsettled derivatives		364			429			(1,658		)

Total sales from natural gas marketing		$	156		$	875		$	512

Cost of natural gas marketing
Net settlements		$	346		$	(257	)	$	(2,029	)

Net change in fair value of unsettled derivatives		(451		)	(412		)	1,601

Total cost of natural gas marketing		$	(105	)	$	(669	)	$	(428	)



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, 2014 and 2013:


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




As of December 31, 2013		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		$	6,024		$	(4,637	)	$	1,387


Liability derivatives:
Derivative instruments, at fair value		$	17,531		$	(4,637	)	$	12,894

CONCENTRATION_OF_RISK_Accounts

CONCENTRATION OF RISK Accounts Receivable, net of Allowance for Doubtful Accounts (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013
		(in thousands)

	Crude oil, natural gas and NGLs sales	$	49,531		$	61,197
	Crude oil, natural gas and NGLs sales	$	49,531		$	61,197
	Joint interest billings	52,841			20,085
	Joint interest billings	52,841			20,085
	Derivative counterparties	12,582			1,025
	Derivative counterparties	12,582			1,025
	Insurance reimbursement	11,212			—
	Insurance reimbursement	11,212			—
	Other	5,524			6,700
	Other	5,524			6,700
	Allowance for doubtful accounts	(486		)	(896		)
	Accounts receivable, net	$	131,204		$	88,111
	Accounts receivable, net	$	131,204		$	88,111

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		2014		2013			2012

	Suncor Energy Marketing, Inc.		19.7	%	35.9	%		39.1	%
	Concord Energy		18.3	%	—	%		—	%
	DCP Midstream, LP		15.1	%	13.9	%		16	%
	Teppco Crude Oil, LLC		12.9	%	8	%		2.4	%
Fair Value, Concentration of Risk [Table Text Block]	The following table presents the counterparties that expose us to credit risk as of December 31, 2014, with regard to our derivative assets:



			Fair Value of
			Derivative Assets
	Counterparty Name		As of December 31, 2014
			(in thousands)

	JP Morgan Chase Bank, N.A (1)		$	95,294
	JP Morgan Chase Bank, N.A (1)		$	95,294
	Canadian Imperial Bank of Commerce (1)		61,570
	Canadian Imperial Bank of Commerce (1)		61,570
	NATIXIS (1)		45,214
	NATIXIS (1)		45,214
	Wells Fargo Bank, N.A. (1)		41,844
	Wells Fargo Bank, N.A. (1)		41,844
	Key Bank N.A. (1)		24,899
	Key Bank N.A. (1)		24,899
	Bank of Nova Scotia (1)		23,760
	Bank of Nova Scotia (1)		23,760
	Other lenders in our revolving credit facility		7,726
	Other lenders in our revolving credit facility		7,726
	Various (2)		7
	Various (2)		7
	Total		$	300,314
	Total		$	300,314

	____________
	(1)Major lender in our revolving credit facility. See Note 8, Long-Term Debt.
	(2)Represents a total of 2 counterparties.
Notes Receivable [Table Text Block]	The following table presents information regarding our note receivable outstanding as of December 31, 2014:


		Amount
		(in thousands)
	Note Receivable:
	Principal outstanding, October 14, 2014	$	39,048
	Principal outstanding, October 14, 2014	$	39,048
	Paid-In-Kind interest	659
	Paid-In-Kind interest	659
	Principal outstanding, December 31, 2014	$	39,707
	Principal outstanding, December 31, 2014	$	39,707

PROPERTIES_AND_EQUIPMENT_Prope

PROPERTIES AND EQUIPMENT Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013
		(in thousands)
	Properties and equipment, net:
	Crude oil and natural gas properties
	Proved	$	2,267,165		$	1,677,271

	Unproved	188,206			253,464

	Total crude oil and natural gas properties	2,455,371			1,930,735

	Equipment and other	29,562			28,832

	Land and buildings	9,015			9,782

	Construction in progress	137,937			41,180

	Properties and equipment, at cost	2,631,885			2,010,529

	Accumulated DD&A	(831,699		)	(529,543		)
	Properties and equipment, net	$	1,800,186		$	1,480,986


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,
		2014			2013			2012
		(in thousands)
	Continuing operations:
	Impairment of proved properties	$	112,557		$	48,750		$	—

	Impairment of unproved properties	45,732			517			1,011

	Amortization of individually insignificant unproved properties	4,465			3,242			4,009

	Other	778			—			—

	Total continuing operations	163,532			52,509			5,020

	Discontinued operations:
	Impairment of proved properties	—			—			161,185

	Impairment of unproved properties	433			566			931

	Amortization of individually insignificant unproved properties	—			363			1,013

	Total discontinued operations	433			929			163,129

	Total impairment of crude oil and natural gas properties	$	163,965		$	53,438		$	168,149


Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]	The following table presents the capitalized exploratory well costs pending determination of proved reserves included in properties and equipment on the consolidated balance sheets:



		2013

		(in thousands)



	Balance beginning of year, January 1,	$	19,567

	Additions to capitalized exploratory well costs pending the determination of proved reserves	2,105

	Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(21,672		)
	Capitalized exploratory well costs charged to expense	—

	Balance end of year, December 31,	$	—



	Number of wells pending determination at December 31,	—

INCOME_TAXES_Income_Taxes_Tabl

INCOME TAXES Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014				2013				2012
		(in thousands)
	Current:
	Federal	$	(1,514	)		$	1,355			$	—

	State	966				199				(199		)

	Total current income taxes	(548		)		1,554				(199		)

	Deferred:
	Federal	(60,698		)		8,238				10,896

	State	(8,721		)		2,060				636

	Total deferred income taxes	(69,419		)		10,298				11,532

	Income tax benefit (expense) from continuing operations	$	(69,967	)		$	11,852			$	11,333


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,
		2014			2013			2012

	Statutory tax rate	35	%		35	%		35	%
	State income tax, net	2.8			4			0.9

	Percentage depletion	(0.3	)		2.2			2

	Non-deductible compensation	0.7			(4.2	)		(0.5	)

	Other	1.3			(1.0	)		(0.5	)

	Effective tax rate	39.5	%		36	%		36.9	%

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, 2014 and 2013 are presented below:



		As of December 31,
		2014				2013
		(in thousands)
	Deferred tax assets:
	Net change in fair value of unsettled derivatives	$	—			$	6,205

	Deferred compensation	10,459				8,507

	Asset retirement obligations	28,051				11,630

	State NOL and tax credit carryforwards, net	3,761				5,182

	Percentage depletion - carryforward	—				4,570

	Alternative minimum tax - credit carryforward	2,906				3,165

	Federal NOL carryforward	—				4,601

	Settlement of class action litigation	12,259				—

	Other	3,144				6,229

	Deferred tax assets	60,580				50,089


	Deferred tax liabilities:
	Properties and equipment	130,155				120,746

	Investment in PDCM	—				21,962

	Net change in fair value of unsettled derivatives	113,007				—

	Convertible debt	2,285				3,774

	Total gross deferred tax liabilities	245,447				146,482

	Net deferred tax liability	$	184,867			$	96,393


	Classification in the consolidated balance sheets:
	Deferred income tax assets	$	—			$	22,374

	Deferred income tax liability - current	59,174				—

	Deferred income tax liability - non-current	125,693				118,767

	Net deferred tax liability	$	184,867			$	96,393

LONGTERM_DEBT_LONGTERM_DEBT_Ta

LONG-TERM DEBT LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013
		(in thousands)
	Senior notes:
	3.25% Convertible senior notes due 2016:
	Principal amount	$	115,000		$	115,000

	Unamortized discount	(6,077		)	(10,010		)
	3.25% Convertible senior notes due 2016, net of discount	108,923			104,990

	7.75% Senior notes due 2022	500,000			500,000

	Total senior notes	608,923			604,990

	Revolving credit facility	56,000			—

	Long-term debt	664,923			604,990


	PDCM credit facility	—			37,000

	PDCM second lien term loan	—			15,000

	PDCM long-term debt (included in liabilities held for sale - non-current)	—			52,000


	Total debt	$	664,923		$	656,990

ASSET_RETIREMENT_OBLIGATIONS_A

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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:


		2014			2013
		(in thousands)

	Balance at beginning of period, January 1, 2014	$	41,030		$	62,563

	Revisions in estimated cash flows	31,945			612

	Obligations incurred with development activities	1,170			2,389

	Accretion expense	3,455			4,747

	Obligations discharged with divestitures of properties and asset retirements	(3,745		)	(29,281		)
	Balance end of period, December 31, 2014	73,855			41,030

	Less: Liabilities held for sale (1)	—			(2,234		)

	Less: Current portion	(1,863		)	(1,158		)
	Long-term portion	$	71,992		$	37,638

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Tables)	12 Months Ended
	Dec. 31, 2014
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	2015		2016		2017		2018		2019 and		Total		Expiration
										Through				Date
										Expiration

	Natural gas (MMcf)
	Appalachian Basin	7,117		7,136		7,117		7,117		25,803		54,290		August 31, 2022

	Utica Shale	2,737		2,745		2,737		2,737		12,549		23,505		July 22, 2023

	Total	9,854		9,881		9,854		9,854		38,352		77,795


	Crude oil (MBbls)
	Wattenberg Field	1,818		2,420		2,413		2,413		3,010		12,074		April 30, 2020


	Dollar commitment (in thousands)	$	14,481	$	17,624	$	17,158	$	16,327	$	30,361	$	95,951


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, 2014:



		Year Ending December 31,
		2015		2016		2017		2018		2019		Thereafter		Total
		(in thousands)

	Minimum Lease Payments	$	2,517	$	2,285	$	2,099	$	1,908	$	1,937	$	2,091	$	12,837

COMMON_STOCK_Common_Stock_Tabl

COMMON STOCK Common Stock (Tables)	12 Months Ended
COMMON STOCK Common Stock (Tables)	Dec. 31, 2014
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,
			2014				2013				2012
			(in thousands)

	Stock-based compensation expense		$	17,518			$	12,880			$	8,495
	Stock-based compensation expense		$	17,518			$	12,880			$	8,495
	Income tax benefit		(5,955		)		(4,697		)		(3,245		)
	Net stock-based compensation expense		$	11,563			$	8,183			$	5,250
	Net stock-based compensation expense		$	11,563			$	8,183			$	5,250

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	In January 2014, the Compensation Committee awarded 88,248 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,
		2014				2013				2012

	Expected term of award	6 years				6 years				6 years
	Expected term of award	6 years				6 years				6 years
	Risk-free interest rate	2.1		%		1		%		1.1		%
	Expected volatility	65.6		%		65.5		%		64.3		%
	Weighted-average grant date fair value per share	$	29.96			$	21.96			$	17.61
	Weighted-average grant date fair value per share	$	29.96			$	21.96			$	17.61
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity [Table Text Block]	The following table presents the changes in our SARs:



		Year Ended December 31,
		2014												2013							2012
		Number of			Weighted-Average				Average Remaining Contractual			Aggregate Intrinsic		Number of		Weighted-Average		Aggregate Intrinsic			Number of	Weighted-Average		Aggregate Intrinsic
		SARs			Exercise				Term (in years)			Value (in thousands)		SARs		Exercise		Value (in thousands)			SARs	Exercise		Value (in thousands)
					Price											Price						Price
	Outstanding beginning of year, January 1,	190,763			$	33.77			8.2			$	3,711	118,832		$	30.8	$	486		50,471	$	31.61	$	341
	Outstanding beginning of year, January 1,	190,763			$	33.77			8.2			$	3,711	118,832		$	30.8	$	486		50,471	$	31.61	$	341
	Awarded	88,248			49.57				—			—		87,078		37.18		—			68,361	30.19		—
	Awarded	88,248			49.57				—			—		87,078		37.18		—			68,361	30.19		—
	Exercised	—			—				—			—		(15,147	)	30.06		425			—	—		—
	Exercised	—			—				—			—		(15,147	)	30.06		425			—	—		—
	Outstanding at December 31,	279,011			38.77				7.8			1,472		190,763		33.77		3,711			118,832	30.8		486
	Outstanding at December 31,	279,011			38.77				7.8			1,472		190,763		33.77		3,711			118,832	30.8		486
	Exercisable at December 31,	139,334			36.27				7.3			982		51,922		29.97		1,207			27,458	28.84		187
	Exercisable at December 31,	139,334			36.27				7.3			982		51,922		29.97		1,207			27,458	28.84		187
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 2014:


		Shares			Weighted-Average
					Grant-Date
					Fair Value

	Non-vested at December 31, 2013	651,781			$	36.36
	Non-vested at December 31, 2013	651,781			$	36.36
	Granted	291,370			56.45
	Granted	291,370			56.45
	Vested	(328,071	)		36.26
	Vested	(328,071	)		36.26
	Forfeited	(50,748	)		45.04
	Forfeited	(50,748	)		45.04
	Non-vested at December 31, 2014	564,332			46.02
	Non-vested at December 31, 2014	564,332			46.02




		As of/Year Ended December 31,
		2014				2013				2012
		(in thousands, except per share data)

	Total intrinsic value of time-based awards vested	$	18,278			$	13,640			$	5,950
	Total intrinsic value of time-based awards vested	$	18,278			$	13,640			$	5,950
	Total intrinsic value of time-based awards non-vested	23,290				34,688				21,470
	Total intrinsic value of time-based awards non-vested	23,290				34,688				21,470
	Market price per common share as of December 31,	41.27				53.22				33.21
	Market price per common share as of December 31,	41.27				53.22				33.21
	Weighted-average grant date fair value per share	56.45				45.53				26.59
	Weighted-average grant date fair value per share	56.45				45.53				26.59
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block]	In January 2014, the Compensation Committee awarded a total of 42,151 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 set group of 15 peer companies. The shares are measured over a three-year period ending on December 31, 2016 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,
			2014				2013

	Expected term of award		3 years				3 years
	Expected term of award		3 years				3 years
	Risk-free interest rate		0.8		%		0.4		%
	Expected volatility		55.2		%		56.6		%
	Weighted-average grant date fair value per share		$	56.87			$	49.04
	Weighted-average grant date fair value per share		$	56.87			$	49.04
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	The following table presents the change in non-vested market-based awards during 2014:


			Shares			Weighted-Average
						Grant-Date
						Fair Value per Share

	Non-vested at December 31, 2013		72,111			$	43.75
	Non-vested at December 31, 2013		72,111			$	43.75
	Granted		42,151			56.87
	Granted		42,151			56.87
	Vested		(30,541	)		36.54
	Vested		(30,541	)		36.54
	Non-vested at December 31, 2014		83,721			52.98
	Non-vested at December 31, 2014		83,721			52.98




		As of/Year Ended December 31,
		2014				2013				2012
		(in thousands, except per share data)

	Total intrinsic value of market-based awards vested	$	1,260			$	724			$	—
	Total intrinsic value of market-based awards vested	$	1,260			$	724			$	—
	Total intrinsic value of market-based awards non-vested	3,455				3,838				1,352
	Total intrinsic value of market-based awards non-vested	3,455				3,838				1,352
	Market price per common share as of December 31,	41.27				53.22				33.21
	Market price per common share as of December 31,	41.27				53.22				33.21
	Weighted-average grant date fair value per share	56.87				49.04				36.54
	Weighted-average grant date fair value per share	56.87				49.04				36.54
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial:



		Year Ended December 31,
		2014												2013				2012
		Number of			Weighted-Average				Weighted- Average			Aggregate Intrinsic		Number of		Weighted-Average		Number of		Weighted-Average
		Shares			Exercise				Remaining			Value (in thousands)		Shares		Exercise		Shares		Exercise
		Underlying			Price				Contractual					Underlying		Price		Underlying		Price
		Options			Per Share				Term (in years)					Options		Per Share		Options		Per Share
	Outstanding beginning of year, January 1,	3,523			$	44.95			2.2			$	—	6,973		$	41.09	6,973		$	41.09
	Outstanding beginning of year, January 1,	3,523			$	44.95			2.2			$	—	6,973		$	41.09	6,973		$	41.09
	Exercised	—			—				—			—		(3,450	)	37.15		—		—
	Exercised	—			—				—			—		(3,450	)	37.15		—		—
	Outstanding end of year, December 31,	3,523			44.95				1.2			—		3,523		44.95		6,973		41.09
	Outstanding end of year, December 31,	3,523			44.95				1.2			—		3,523		44.95		6,973		41.09
	Exercisable at December 31,	3,523			44.95				1.2			—		3,523		44.95		6,973		41.09
	Exercisable at December 31,	3,523			44.95				1.2			—		3,523		44.95		6,973		41.09

EARNINGS_PER_SHARE_Tables

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014	2013	2012
		(in thousands)

	Weighted-average common shares outstanding - basic	35,784	32,426	27,677

	Dilutive effect of:
	Restricted stock	279	—	—

	Stock options	1	—	—

	SARs	45	—	—

	Non-employee director deferred compensation	5	—	—

	Convertible notes	564	—	—

	Weighted-average common shares and equivalents outstanding - diluted	36,678	32,426	27,677


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,
		2014	2013	2012
		(in thousands)

	Weighted-average common share equivalents excluded from diluted earnings
	per share due to their anti-dilutive effect:
	Restricted stock	8	823	694

	SARs	26	72	116

	Stock options	—	7	7

	Non-employee director deferred compensation	—	4	3

	Convertible notes	—	518	—

	Total anti-dilutive common share equivalents	34	1,424	820

ASSETS_HELD_FOR_SALE_DIVESTITU1

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Assets Held for Sale, Divestitures and Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
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 balance sheet data related to net assets held for sale:



	Consolidated balance sheet		As of December 31, 2014				As of December 31, 2013

	Assets
	Current assets
	Cash and cash equivalents		$	—			$	601

	Other current assets		—				7,060

	Assets held for sale - current		—				7,661


	Non-current assets
	Properties and equipment, net		2,874				175,244

	Other assets		—				6,892

	Assets held for sale - non-current		2,874				182,136


	Liabilities
	Liabilities held for sale - current		—				12,069


	Non-current liabilities
	Long-term debt		—				52,000

	Asset retirement obligation		—				2,234

	Other liabilities		—				1,681

	Liabilities held for sale - non-current		—				55,915


	Net Assets		$	2,874			$	121,813


	Assets held for sale as of December 31, 2014 represents the carrying value of approximately 12 acres of land located adjacent to a regional office. Assets held for sale as of December 31, 2013 represents our proportionate share of PDCM's net assets and the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters.



	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			2012
			(in thousands)
	Revenues
	Crude oil, natural gas and NGLs sales		$	24,149			$	39,001		$	46,793

	Sales from natural gas marketing		—				2,825			1,708

	Commodity price risk management gain (loss), net		(1,085		)		14			3,060

	Well operations, pipeline income and other		48				922			1,926

	Total revenues		23,112				42,762			53,487


	Costs, expenses and other
Production costs		7,120				16,515			27,770

Cost of natural gas marketing		—				2,673			1,529

Impairment of crude oil and natural gas properties		433				929			163,129

Depreciation, depletion and amortization		9,128				13,894			55,768

Other		3,445				7,266			8,791

(Gain) loss on sale of properties and equipment		(76,479		)		1,700			(24,090		)

Total costs, expenses and other		(56,353		)		42,977			232,897


Interest expense		(2,222		)		(1,755		)	(782		)
Interest income		194				10			1

Income (loss) from discontinued operations		77,437				(1,960		)	(180,191		)

Provision for income taxes		(29,263		)		770			68,834

Income (loss) from discontinued operations, net of tax		$	48,174			$	(1,190	)	$	(111,357	)

ACQUISITIONS_Acquisitions_Tabl

ACQUISITIONS Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of crude oil and natural gas properties during 2012:



		Year Ended December 31, 2012
		(in thousands)

	Total acquisition cost	$	304,643


	Recognized amounts of identifiable assets acquired and liabilities assumed:
	Assets acquired:
	Crude oil and natural gas properties - proved	$	180,696

	Crude oil and natural gas properties - unproved	151,428

	Other assets	3,631

	Total assets acquired	335,755

	Liabilities assumed:
	Asset retirement obligation	14,833

	Other accrued expenses	9,574

	Other liabilities	6,705

	Total liabilities assumed	31,112

	Total identifiable net assets acquired	$	304,643


Business Acquisition, Pro Forma Information [Table Text Block]	Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 2012 closing date. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 assuming the Merit Acquisition had been completed as of January 1, 2012, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results.


		Year Ended December 31, 2012
		(in thousands, except per share amounts)

	Total revenues	$	370,488

	Total costs, expenses and other	521,178

	Net income (loss)	$	(119,343	)

	Earnings per share:
	Basic	$	(4.31	)
	Diluted	$	(4.31	)

BUSINESS_SEGMENTS_Business_Seg

BUSINESS SEGMENTS Business Segments (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of Segment Reporting Information [Table Text Block]	The following tables present our segment information:



		2014			2013			2012
		(in thousands)
	Year Ended December 31,
	Segment revenues:
	Oil and gas exploration and production	$	784,636		$	322,878		$	261,765

	Gas marketing	71,571			69,787			45,371

	Total revenues	$	856,207		$	392,665		$	307,136


	Segment income (loss) before income taxes:
	Oil and gas exploration and production	$	344,149		$	81,913		$	101,324

	Gas marketing	(445		)	(297		)	348

	Unallocated	(166,476		)	(114,579		)	(132,360		)
	Income (loss) before income taxes	$	177,228		$	(32,963	)	$	(30,688	)


	Expenditures for segment long-lived assets:
	Oil and gas exploration and production	$	623,912		$	403,227		$	656,443

	Unallocated	4,680			1,379			3,509

	Total	$	628,592		$	404,606		$	659,952


	As of December 31,
	Segment assets:
	Oil and gas exploration and production	$	2,254,751		$	1,751,106

	Gas marketing	6,979			20,342

	Unallocated	75,984			63,958

	Assets held for sale	2,874			189,797

	Total assets	$	2,340,588		$	2,025,203

SUPPLEMENTAL_INFORMATION_NATUR1

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, 2014
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities [Abstract]
Schedule of Prices Used to Estimate Natural Gas and Crude Oil Reserves [Table Text Block]	The price used to estimate our reserves, by commodity, are presented below.



			Price Used to Estimate Reserves

	As of December 31,		Crude Oil				Natural Gas				NGLs
			(per Bbl)				(per Mcf)				(per Bbl)

	2014		$	84.65			$	3.92			$	32.27

	2013		82.18				3.22				29.92

	2012		87.51				2.35				28.02

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			NGLs			Total
					(MMcf)			(MBbls)			(MBoe)
	Proved Reserves:
	Proved reserves, January 1, 2012 (1)	37,636			672,145			19,588			169,248

	Revisions of previous estimates	(6,729	)		(289,436	)		(3,671	)		(58,639	)
	Extensions, discoveries and other additions	27,482			172,933			11,637			67,941

	Purchases of reserves	10,801			87,212			8,084			33,420

	Dispositions	(7,854	)		(6,406	)		(1,970	)		(10,891	)
	Production	(2,026	)		(32,410	)		(841	)		(8,269	)
	Proved reserves, December 31, 2012 (2)	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	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 (3)	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	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




	Proved Developed Reserves, as of:
	January 1, 2012 (1)	16,910			299,369			11,753			78,558

	December 31, 2012 (2)	20,412			281,925			14,353			81,753

	December 31, 2013 (3)	23,997			220,387			14,825			75,553

	31-Dec-14	26,798			186,633			17,002			74,905

	Proved Undeveloped Reserves, as of:

	January 1, 2012 (1)	20,726			372,776			7,835			90,690

	December 31, 2012 (2)	38,898			322,113			18,474			111,058

	December 31, 2013 (3)	69,833			519,253			33,846			190,221

	31-Dec-14	73,717			350,339			43,117			175,224


	__________

	-1	Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian assets. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively.

	-2	Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, 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.

-3	Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 14, 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, 2012	78,558			90,690			169,248

Undeveloped reserves converted to developed	7,655			(7,655	)		—

Revisions of previous estimates	(18,318	)		(40,321	)		(58,639	)
Extensions, discoveries and other additions	11,298			56,643			67,941

Purchases of reserves	13,542			19,878			33,420

Dispositions	(2,713	)		(8,178	)		(10,891	)
Production	(8,269	)		—			(8,269	)

Ending proved reserves, December 31, 2012	81,753			111,057			192,810

Undeveloped reserves converted to developed	3,212			(3,212	)		—

Revisions of previous estimates	(6,751	)		(39,729	)		(46,480	)
Extensions, discoveries and other additions	19,830			122,105			141,935

Purchases of reserves	1,043			—			1,043

Dispositions	(16,104	)		—			(16,104	)

Production	(7,430	)		—			(7,430	)

Ending proved reserves, December 31, 2013	75,553			190,221			265,774

Undeveloped reserves converted to developed	12,730			(12,730	)		—

Revisions of previous estimates	(22,827	)		(41,998	)		(64,825	)
Extensions, discoveries and other additions	27,957			70,072			98,029

Purchases of reserves	17			—			17

Dispositions	(9,231	)		(30,341	)		(39,572	)
Production	(9,294	)		—			(9,294	)

Ending proved reserves, December 31, 2014	74,905			175,224			250,129


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,

		2014				2013				2012

		(in thousands)

	Revenue:

	Crude oil, natural gas and NGLs sales	$	495,562			$	379,796			$	274,783

	Commodity price risk management gain, net	309,219				(23,905		)		32,339

		804,781				355,891				307,122

	Expenses:
	Production costs	90,744				81,365				77,537

	Exploration expense	948				7,071				22,605

	Impairment of proved crude oil and natural gas properties	163,965				53,438				162,287

	Depreciation, depletion, and amortization	201,656				124,202				146,879

	Accretion of asset retirement obligations	3,455				4,747				4,060

	(Gain) loss on sale of properties and equipment	(75,972		)		3,722				(24,273		)

		384,796				274,545				389,095

	Results of operations for crude oil and natural gas producing	419,985				81,346				(81,973		)
	activities before provision for income taxes


	Provision for income taxes	(163,647		)		(29,400		)		31,163



	Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	256,338			$	51,946			$	(50,810	)


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,
		2014				2013				2012
		(in thousands)
	Acquisition of properties: (1)
	Proved properties	$	11,973			$	28,698			$	105,303

	Unproved properties	45,999				3,390				276,225

	Development costs (2)	590,855				332,250				233,144

	Exploration costs: (3)
	Exploratory drilling	—				58,988				18,803

	Geological and geophysical	1				752				1,925

	Total costs incurred	$	648,828			$	424,078			$	635,400


	__________

	-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, 2014, 2013 and 2012, $125.2 million, $40.1 million and $62.0 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,
		2014				2013
		(in thousands)

	Proved crude oil and natural gas properties	$	2,267,165			$	1,677,271

	Unproved crude oil and natural gas properties	188,206				253,463

	Uncompleted wells, equipment and facilities	137,134				40,745

	Capitalized costs	2,592,505				1,971,479

	Less accumulated DD&A	(808,431		)		(507,510		)
	Capitalized costs, net	$	1,784,074			$	1,463,969



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,
		2014				2013				2012
		(in thousands)

	Future estimated cash flows	$	12,550,515			$	11,550,917			$	7,529,292

	Future estimated production costs	(2,816,776		)		(2,329,836		)		(1,690,453		)
	Future estimated development costs	(2,458,790		)		(2,778,148		)		(1,852,177		)
	Future estimated income tax expense	(2,336,510		)		(2,119,615		)		(1,230,294		)
	Future net cash flows	4,938,439				4,323,318				2,756,368

	10% annual discount for estimated timing of cash flows	(2,631,974		)		(2,541,155		)		(1,587,871		)
	Standardized measure of discounted future estimated net cash flows	$	2,306,465			$	1,782,163			$	1,168,497



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,
		2014				2013				2012
		(in thousands)

	Sales of crude oil, natural gas and NGLs production, net of production costs	$	(387,789	)		$	(286,021	)		$	(194,346	)
	Net changes in prices and production costs (1)	129,213				89,527				95,501

	Extensions, discoveries, and improved recovery, less related costs (2)	1,444,581				1,529,006				632,781

	Sales of reserves (3)	(402,595		)		(142,724		)		(86,902		)
	Purchases of reserves (4)	238				10,610				296,208

	Development costs incurred during the period	161,404				46,366				69,198

	Revisions of previous quantity estimates (5)	(654,318		)		(397,738		)		(452,775		)
	Changes in estimated income taxes (6)	(221,874		)		(381,369		)		(131,256		)
	Net changes in future development costs	46,499				(40,707		)		(3,979		)

	Accretion of discount	270,389				142,040				124,105

	Timing and other	138,554				44,676				(121,247		)

	Total	$	524,302			$	613,666			$	227,288


	__________

	-1	Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to $37.78 as compared to $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. Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $30.82 from $30.28 in our 2012 report due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which increased our liquids as a percentage of proved reserves.

	-2	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. The 142% increase in 2013 as compared to 2012 is primarily due to the addition of PUDs in the Utica Shale and our continued focus on our Wattenberg Field drilling program. Our increased PUD count in the Wattenberg Field is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report.

	-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. The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013.

	-4	The decrease in purchases of reserves in 2014 and 2013 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 2014 as compared to 2013 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule.

	-6	The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38%, 38% and 38.2% for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital.

NATURE_OF_OPERATIONS_AND_BASIS1

NATURE OF OPERATIONS AND BASIS OF PRESENTATION Additional Information (Details)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Oil and gas producing wells, gross	2,900
Number of Operating Segments	2

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Detail (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Plicies [Line Items]
Certificates of Deposit and Cash	$700,000	$3,300,000
Inventory, Net	800,000	900,000
Impairment of other property and equipment	778,000	0
Non-Oil and gas Depreciation, Depletion and Amortization	4,100,000	4,000,000	4,800,000
Capitalized Interest	3,500,000	1,700,000	900,000
Production Tax Liability	26,400,000	22,100,000
Debt Issuance Cost	13,700,000	16,600,000
Restricted Cash [Member]
Significant Accounting Plicies [Line Items]
Certificates of Deposit and Cash		2,200,000
Other Assets [Member]
Significant Accounting Plicies [Line Items]
Certificates of Deposit and Cash		1,100,000
7.75% Senior Notes [Member]
Significant Accounting Plicies [Line Items]
Debt Issuance Cost	8,700,000	9,800,000
Debt Instrument, Interest Rate, Stated Percentage	7.75%
Revolving Credit Facility [Member]
Significant Accounting Plicies [Line Items]
Debt Issuance Cost	4,300,000	5,500,000
3.25% Convertible Note [Member]
Significant Accounting Plicies [Line Items]
Debt Issuance Cost	$700,000	$1,300,000

FAIR_VALUE_MEASUREMENTS_AND_DI2

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
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	$237,939,000	$3,852,000
Basis Protection Derivative Assets	19,000	74,000
Assets, Fair Value Disclosure	237,958,000	3,926,000
Commodity Based Derivative Liabilities	742,000	16,539,000
Basis Protection Derivative Liabilities	25,000	5,000
Liabilities, Fair Value Disclosure	767,000	16,544,000
Net Asset Fair Value	237,191,000	-12,618,000
Fair Value \| Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Based Derivative Assets	62,356,000	2,098,000
Basis Protection Derivative Assets	0	0
Assets, Fair Value Disclosure	62,356,000	2,098,000
Commodity Based Derivative Liabilities	0	987,000
Basis Protection Derivative Liabilities	0	0
Liabilities, Fair Value Disclosure	0	987,000
Net Asset Fair Value	62,356,000	1,111,000
Fair Value \| Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Based Derivative Assets	300,295,000	5,950,000
Basis Protection Derivative Assets	19,000	74,000
Assets, Fair Value Disclosure	300,314,000	6,024,000
Commodity Based Derivative Liabilities	742,000	17,526,000
Basis Protection Derivative Liabilities	25,000	5,000
Liabilities, Fair Value Disclosure	767,000	17,531,000
Net Asset Fair Value	299,547,000	-11,507,000
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	137,500,000
3.25% convertible senior notes fair value as a percentage of par	119.60%
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	$452,500,000
7.75% senior notes fair value as percentage of par	90.50%

FAIR_VALUE_MEASUREMENTS_AND_DI3

FAIR VALUE MEASUREMENTS AND DISCLOSURES Reconciliation of Level 3 Fair Value Measurements (Details) (Derivative Financial Instrument Net Assets [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
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	$62,356		$1,111		$13,610		$22,107
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	15,635		-2,727		3,666
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	62,003		-1,748		7,517
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	-737		-6,361		-15,644
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	15,632		-2,731		3,665
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	-22		13		63
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	1		-37		-114
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	3		4		1
Accounts Payable Affiliates [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Changes in Fair Value Included in Balance Sheet Line Item	0	[1]	0	[1]	-319	[1]
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		($4,366)		$0

[1]	Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.

DERIVATIVE_FINANCIAL_INSTRUMEN2

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value of Derivative and Balance Sheet Location (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$767	$17,531
Derivative Asset, Fair Value, Gross Asset	300,314	6,024
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	187,495	1,521
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	112,819	4,503
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	570	14,689
Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	197	2,842
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] \| Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	186,886	1,086
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] \| Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	112,599	4,225
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] \| Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	0	14,437
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] \| Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	0	2,609
Commodity Contracts Related to Natural Gas Marketing [Member] \| Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	590	361
Commodity Contracts Related to Natural Gas Marketing [Member] \| Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	220	278
Commodity Contracts Related to Natural Gas Marketing [Member] \| Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	545	247
Commodity Contracts Related to Natural Gas Marketing [Member] \| Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	197	233
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] \| Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	19	74
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] \| Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	25	0
Basis Protection Contracts Related to Natural Gas Marketing [Member] \| Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	$0	$5

DERIVATIVE_FINANCIAL_INSTRUMEN3

DERIVATIVE FINANCIAL INSTRUMENTS Impact of Derivative Instruments on Statement of Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commodity Price Risk Management, net
Derivative [Line Items]
Net settlements	($837)	$11,177	$43,591
Net change in fair value of unsettled derivatives	311,141	-35,096	-14,312
Total Derivative Gain (Loss)	310,304	-23,919	29,279
Sales From Natural Gas Marketing
Derivative [Line Items]
Net settlements	-208	446	2,170
Net change in fair value of unsettled derivatives	364	429	-1,658
Total Derivative Gain (Loss)	156	875	512
Cost of Natural Gas Marketing
Derivative [Line Items]
Net settlements	346	-257	-2,029
Net change in fair value of unsettled derivatives	-451	-412	1,601
Total Derivative Gain (Loss)	($105)	($669)	($428)

DERIVATIVE_FINANCIAL_INSTRUMEN4

DERIVATIVE FINANCIAL INSTRUMENTS Effect of Master Netting Agreements (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$300,314	$6,024
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	-29	-4,637
Derivative Asset	300,285	1,387
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	767	17,531
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-29	-4,637
Derivative Liability	$738	$12,894

DERIVATIVE_FINANCIAL_INSTRUMEN5

DERIVATIVE FINANCIAL INSTRUMENTS Additional Information (Details)	Dec. 31, 2014
	MBbls
	MMBTU
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Portion of Anticipated Natural Gas Production Hedged (MMBtu)	65,215,000
Portion of Future Oil and Gas Production Being Hedged (MBbls)	9,340

CONCENTRATION_OF_RISK_Accounts1

CONCENTRATION OF RISK Accounts Receivable, Net of Allowance for Doubtful Accounts (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk [Line Items]
Allowance for Doubtful Accounts Receivable, Current	($486)	($896)
Accounts Receivable, Net, Current	131,204	88,111
Natural gas, NGLs and crude oil sales
Concentration Risk [Line Items]
Accounts Receivable, Gross	49,531	61,197
Joint interest billing
Concentration Risk [Line Items]
Accounts Receivable, Gross	52,841	20,085
Derivative Counterparties [Member] [Member]
Concentration Risk [Line Items]
Accounts Receivable, Gross	12,582	1,025
Insurance Reimbursement [Member]
Concentration Risk [Line Items]
Accounts Receivable, Gross	11,212	0
Other Accounts Receivable
Concentration Risk [Line Items]
Accounts Receivable, Gross	$5,524	$6,700

CONCENTRATION_OF_RISK_Customer

CONCENTRATION OF RISK Customer Constituting 10% or more of Total Revenue (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Rate	Rate	Rate
Suncor Energy Marketing, Inc.
Concentration Risk [Line Items]
Percentage of Revenue	19.70%	35.90%	39.10%
Percentage of Accounts Receivable Balance at Year-End	11.10%
Concord Energy
Concentration Risk [Line Items]
Percentage of Revenue	18.30%	0.00%	0.00%
Percentage of Accounts Receivable Balance at Year-End	10.30%
DCP Midstream, LP
Concentration Risk [Line Items]
Percentage of Revenue	15.10%	13.90%	16.00%
Teppco Crude Oil
Concentration Risk [Line Items]
Percentage of Revenue	12.90%	8.00%	2.40%

CONCENTRATION_OF_RISK_Derivati

CONCENTRATION OF RISK Derivative Counterparties (Details) (USD $)	Dec. 31, 2014
Concentration Risk [Line Items]
Fair Value of Derivative Assets	$300,314,000
Number of derivative counterparties	2
JP Morgan Chase Bank, N.A.
Concentration Risk [Line Items]
Fair Value of Derivative Assets	95,294,000	[1]
Canadian Imperial Bank of Commerce
Concentration Risk [Line Items]
Fair Value of Derivative Assets	61,570,000	[1]
Natixis
Concentration Risk [Line Items]
Fair Value of Derivative Assets	45,214,000	[1]
Wells Fargo Bank
Concentration Risk [Line Items]
Fair Value of Derivative Assets	41,844,000	[1]
Key Bank
Concentration Risk [Line Items]
Fair Value of Derivative Assets	24,899,000	[1]
Bank of Nova Scotia
Concentration Risk [Line Items]
Fair Value of Derivative Assets	23,760,000	[1]
Other Lenders in Our Credit Facility
Concentration Risk [Line Items]
Fair Value of Derivative Assets	7,726,000	[1]
Various
Concentration Risk [Line Items]
Fair Value of Derivative Assets	$7,000	[2]

[1]	Major lender in our revolving credit facility. See Note 8, Long-Term Debt.
[2]	Represents a total of 2 counterparties.Note ReceivableThe following table presents information regarding our note receivable outstanding as of DecemberB 31, 2014:B AmountB (in thousands)Note Receivable:B Principal outstanding, October 14, 2014$39,048Paid-In-Kind interest659Principal outstanding, December 31, 2014$39,707In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 14, 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 bNoteb) 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 bPIK Interestb) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of December 31, 2014, the issuer of the Note had elected to pay-in-kind interest on the Note. 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 without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities issued and certain assets.Under the effective interest method, we recognized $0.9 million of interest income for the year ended December 31, 2014, of which $0.7 million was PIK Interest. As of December 31, 2014, the $39.7 million outstanding balance on the Note was included in the consolidated balance sheet line item other assets.

CONCENTRATION_OF_RISK_Notes_Re

CONCENTRATION OF RISK Notes Receivable (Details) (USD $)	3 Months Ended
CONCENTRATION OF RISK Notes Receivable (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Note Receivable - Principal Outstanding	$39,707,000	$39,048,000
Paid-in-Kind Interest	659,000
Note receivable - interest income	$900,000

PROPERTIES_AND_EQUIPMENT_Prope1

PROPERTIES AND EQUIPMENT Properties and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Proved Natural Gas and Crude Oil Properties	$2,267,165	$1,677,271
Unproved Natural Gas and Crude Oil Properties	188,206	253,464
Total Natural Gas and Crude Oil Properties	2,455,371	1,930,735
Transportation and Other Equipment	29,562	28,832
Land and Buildings	9,015	9,782
Construction in Progress	137,937	41,180
Gross Propertis and Equipment	2,631,885	2,010,529
Accumulated Depreciation, Depletion and Amortization	-831,699	-529,543
Property, Plant and Equipment, Net	$1,800,186	$1,480,986

PROPERTIES_AND_EQUIPMENT_Impai

PROPERTIES AND EQUIPMENT Impairment of Natural Gas and Crude Oil Properties (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Continuing Operations:
Impairment of proved properties									$112,557	$48,750	$0
Impairment of significantly unproved properties									45,732	517	1,011
Amortization of Individually Insignificant Unproved Properties									4,465	3,242	4,009
Other									778	0	0
Total continuing operations	159,911	1,863	848	910	715	4,236	1,298	46,260	163,532	52,509	5,020
Discontinued operations:
Impairment of proved properties									0	0	161,185
Impairment of individually significant unproved properties from discontinued operations									433	566	931
Amortization of Individually Insignificant Unproved Properties, discontinued operations									0	363	1,013
Total discontinued operations									433	929	163,129
Total impairment of natural gas and crude oil properties									163,965	53,438	168,149
Shallow Upper Devonian properties
Continuing Operations:
Impairment of proved properties										48,800
Unproved Properties
Continuing Operations:
Total continuing operations									45,700
Proved Properties
Continuing Operations:
Total continuing operations									112,600
Proved and unproved properties
Continuing Operations:
Total continuing operations									$158,300

PROPERTIES_AND_EQUIPMENT_Suspe

PROPERTIES AND EQUIPMENT Suspended Exploratory Well Costs (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Change in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance beginning of year, January 1,	$19,567
Additions to capitalized exploratory well costs pending determination of proved reserves	2,105
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	-21,672
capitalized well cost	0
Balance end of year, December 31,	$0
Number of wells pending determination	0

INCOME_TAXES_Provision_for_Inc

INCOME TAXES Provision for Income Taxes (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current Federal Tax Benefit (Expense)									($1,514)	$1,355	$0
Current State and Local Tax Benefit (Expense)									966	199	-199
Current Income Tax Benefit (Expense)									-548	1,554	-199
Deferred Federal Income Tax Benefit (Expense)									-60,698	8,238	10,896
Deferred State and Local Income Tax Benefit (Expense)									-8,721	2,060	636
Deferred Income Tax Benefit (Expense)									-69,419	10,298	11,532
Provision for income taxes	($54,115)	($35,396)	$18,650	$894	($8,937)	$9,435	($9,444)	$20,798	($69,967)	$11,852	$11,333

INCOME_TAXES_Reconciliation_of

INCOME TAXES Reconciliation of Statutory Rate to Effective Rate (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Rate	Rate	Rate
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%
State income tax, net	2.80%	4.00%	0.90%
Percentage depletion	-0.30%	2.20%	2.00%
Non-deductible compensation	0.70%	-4.20%	-0.50%
Other	1.30%	-1.00%	-0.50%
Effective tax rate	39.50%	36.00%	36.90%

INCOME_TAXES_Tax_Effects_of_Te

INCOME TAXES Tax Effects of Temporary differences that Give Rise to Significant Portions of the Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Components of Deferred Tax Assets [Abstract]
Deferred Tax Assets, Provision for Underpayment of Natural Gas Sales	$0	$6,205
Deferred compensation	10,459	8,507
Asset retirement obligations	28,051	11,630
State NOL and tax credit carryforwards, net	3,761	5,182
Percentage depletion - Carryforward	0	4,570
Alternative minimum tax - credit carryforward	2,906	3,165
Federal NOL carryforward	0	4,601
Settlement of class action litigation	12,259	0
Other	3,144	6,229
Deferred tax assets	60,580	50,089
Components of Deferred Tax Liabilities [Abstract]
properties and equipment	130,155	120,746
Investment in PDCM	0	21,962
Net change in fair value of unsettled derivatives	113,007	0
Convertible debt	2,285	3,774
Total gross deferred tax liabilities	245,447	146,482
Net deferred tax liability	184,867	96,393
Deferred income tax assets	0	22,374
Deferred Tax Liabilities, Net, Current	59,174	0
Deferred income tax liability	$125,693	$118,767

INCOME_TAXES_Unrecognized_Tax_

INCOME TAXES Unrecognized Tax Benefits (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Unrecognized Tax Benefits:
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$0	$0.10

INCOME_TAXES_Additional_Inform

INCOME TAXES Additional Information (Details) (USD $)	12 Months Ended
INCOME TAXES Additional Information (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards:
Federal NOL carryforward	$0	$4,601,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0	100,000
State NOL Carryforwards
Operating Loss Carryforwards:
State NOL carryforwards	90,000,000
Year Carryforwards Expire	31-Dec-30
State Credit Carryforwards
Operating Loss Carryforwards:
State credit carryforwards	1,300,000
Year Carryforwards Expire	31-Dec-23
3.25% Convertible Senior Notes due 2016 [Member]
Operating Loss Carryforwards:
3.25% convertible senior notes fair value	$115,000,000	$115,000,000

LONGTERM_DEBT_SCHEDULE_OF_LONG

LONG-TERM DEBT SCHEDULE OF LONG-TERM DEBT (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total senior notes	$608,923	$604,990
Loans Payable, Noncurrent	0	15,000
Long-term Debt, Gross	0	52,000
Total long-term debt	664,923	604,990
Long-term Debt	664,923	656,990
Convertible Debt
Debt Instrument [Line Items]
Principal amount	115,000	115,000
Debt Instrument, Unamortized Discount	6,077	10,010
3.25% Convertible senior notes due 2016, net of discount	108,923	104,990
7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	500,000	500,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total credit facilities	56,000	0
PDCM Credit Facility [Member]
Debt Instrument [Line Items]
PDCM Line of Credit Outstanding	0	37,000
Convertible Debt
Debt Instrument [Line Items]
Principal amount	$137,500

LONGTERM_DEBT_ADDITIONAL_INFOR

LONG-TERM DEBT ADDITIONAL INFORMATION (Details) (USD $)

12 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

15-May-16

Nov. 15, 2015

Nov. 15, 2010

Sep. 30, 2014

Oct. 15, 2022

Oct. 03, 2012

21-May-18

21-May-13

Nov. 05, 2010

Debt Instrument [Line Items]

Debt Issuance Costs ($)

$88,000

$2,352,000

$11,969,000

Loss on extinguishment of debt

-23,283,000

3.25% Convertible Senior Notes due 2016 [Member]

Debt Instrument [Line Items]

Debt Instrument, Issuance Date

15-Nov-10

Debt Instrument, Maturity Date

15-May-16

Debt Instrument, Interest Rate, Stated Percentage

3.25%

Debt Instrument, Call Date, Earliest

15-Nov-15

Convertible Senior Note, Shares Issued Upon Conversion

23.5849

Convertible Note Principal Amount

1,000

3.25% Convertible Note, Conversion Price

$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

1 year 4 months 28 days

Debt Instrument, Interest Rate During Period

7.40%

Convertible Debt, Interest Expense ($)

3,700,000

Convertible Debt, Amortization of Debt Discount ($)

3,900,000

3,400,000

Debt Instrument, Convertible, If-converted Value in Excess of Principal

-3,100,000

7.75% Senior Notes due 2022 [Member]

Debt Instrument [Line Items]

Debt Instrument, Issuance Date

3-Oct-12

Debt Instrument, Maturity Date

15-Oct-22

Debt Instrument, Interest Rate, Stated Percentage

7.75%

Debt Instrument, Call Date, Earliest

15-Oct-15

Debt Issuance Costs ($)

11,000,000

Debt Instrument, Call Date, Latest

15-Oct-17

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Initiation Date

5-Nov-10

Line of Credit Facility, Current Borrowing Capacity ($)

450,000,000

Debt agreement Amendment date

21-May-13

Line of Credit Facility, Maximum Borrowing Capacity ($)

1,000,000,000

Line of Credit Facility, Expiration Date

21-May-18

Line of Credit Facility, Remaining Borrowing Capacity

382,300,000

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 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

15-May

First Payment [Member] | 7.75% Senior Notes due 2022 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

15-Apr

Second Payment [Member] | 3.25% Convertible Senior Notes due 2016 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

15-Nov

Second Payment [Member] | 7.75% Senior Notes due 2022 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

15-Oct

PDCM Credit Facility [Member]

Debt Instrument [Line Items]

PDCM Line of Credit Outstanding ($)

37,000,000

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Debt, Weighted Average Interest Rate

4.10%

Maximum Borrowing Base [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Current Borrowing Capacity ($)

$700,000,000

ASSET_RETIREMENT_OBLIGATIONS_A1

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance beginning of year, January 1	$41,030		$62,563
Obligations incurred with development activities and assumed with acquisitions	1,170		2,389
Accretion of asset retirement obligation	3,455		4,747		4,060
Obligations discharged with disposal of properties and asset retirements	-3,745		-29,281
Revisions in estimated cash flows	31,945		612
Balance end of year, December 31	73,855		41,030		62,563
Less: Liabilities held for sale	0	[1]	-2,234	[1]
Less: Current portion	-1,863		-1,158
Long-term portion	$71,992		$37,638

[1]	Represents asset retirement obligations related to assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information.

EMPLOYEE_BENEFIT_PLANS_Employe

EMPLOYEE BENEFIT PLANS Employee Benefit Plan (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Postretirement Benefit Expense	$3.90	$3.70	$3.40
Deferred Compensation Liability, Current and Noncurrent	1.5	1.8
Deferred Compensation Liability, Current	0.3	0.3
Supplemental Health Care Benefits Liability, Noncurrent	$0.70	$0.70

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Oct. 14, 2014
	Dec. 31, 2014	MMcf
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	77,795
Dollar Commitment ($ in thousands)	95,951
First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,854
Dollar Commitment ($ in thousands)	14,481
Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,881
Dollar Commitment ($ in thousands)	17,624
Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,854
Dollar Commitment ($ in thousands)	17,158
Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,854
Dollar Commitment ($ in thousands)	16,327
commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	38,352
Dollar Commitment ($ in thousands)	30,361
Appalachiain Basin
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	54,290
Appalachiain Basin \| First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin \| Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,136
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)	25,803
Appalachiain Basin \| Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	31-Aug-22
Utica Shale
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	23,505
Utica Shale \| First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,737
Utica Shale \| Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,745
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)	12,549
Utica Shale \| Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	22-Jul-23
Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	12,074
Wattenberg Field \| First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	1,818
Wattenberg Field \| Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,420
Wattenberg Field \| Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,413
Wattenberg Field \| Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,413
Wattenberg Field \| commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	3,010
Wattenberg Field \| Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	30-Apr-20
PDCM Divestiture [Member] \| PDCM Divestiture [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)		134,875
Dollar Commitment ($ in thousands)		$30,400

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES Minimum Lease Payments (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Minimum Future Lease Payments under Non-cancelable Operating Leases [Line Items]
2015	$2,517
2016	2,285
2017	2,099
2018	1,908
2019	1,937
Thereafter	2,091
Total	$12,837

COMMITMENTS_AND_CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES Additional information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMcf	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	77,795
Supply Commitment, Remaining Minimum Amount Committed	$95,951,000
Accrued Environmental Liabilities	800,000	5,400,000
Operating Lease Expense	7,000,000	7,000,000	6,100,000
Partnership Class Action [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount	37,500,000
Loss Contingency, Range of Possible Loss, Maximum	175,000,000
Partnership Liquidation Lawsuit [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Expense	8,800,000
PDC Payment [Member] \| Partnership Class Action [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount	31,500,000
Insurance Payment [Member] \| 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 $)	0 Months Ended
COMMON STOCK Stockholders' Equity Note (Details) (USD $)	Aug. 19, 2013	21-May-12	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share			$0.01	$0.01
Common Stock, Value, Issued			$359,000	$357,000
Additional paid-in capital			689,209,000	674,211,000
August 2013 Common Stock Issuance [Member]
Class of Stock [Line Items]
Stock Issuance Date	19-Aug-13
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
May 2012 Common Stock Issuance [Member]
Class of Stock [Line Items]
Stock Issuance Date		21-May-12
Stock Issued During Period, Shares, New Issues		6,500,000
Sale of Stock, Price Per Share		$26.50
Proceeds from Issuance of Common Stock		164,500,000
Common Stock, Value, Issued		65,000
Additional paid-in capital		$164,400,000

COMMON_STOCK_Stock_based_compe

COMMON STOCK Stock based compensation plans (Details)	Dec. 31, 2014	Dec. 31, 2013	Jun. 29, 2010
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Common Stock, Shares Authorized	150,000,000	100,000,000	3,000,000
Common stock shares remain avaliable for issuance	1,401,953

COMMON_STOCK_Stocked_Based_Com

COMMON STOCK Stocked Based Compensation Summary (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$17,518	$12,880	$8,495
Income tax benefit	-5,955	-4,697	-3,245
Net stock-based compensation expense	$11,563	$8,183	$5,250

COMMON_STOCK_Schedule_of_Chang

COMMON STOCK Schedule of Changes in Stock Option Awards (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Number of Shares
Outstanding beginning of year, January 1,	3,523	6,973	6,973
Exercised	0	-3,450	0
Outstanding end of year, December 31,	3,523	3,523	6,973
Exercisable at December 31,	3,523	3,523	6,973
Weighted-Average Exercise Price
Outstanding beginning of year, January 1,	$44.95	$41.09	$41.09
Exercised	$0	$37.15	$0
Outstanding end of year, December 31,	$44.95	$44.95	$41.09
Exercisable at December 31,	$44.95	$44.95	$41.09
Weighted-Average Remaining Contractual Term (in years)
Outstanding at December 31,		2 years 2 months 12 days
Exercisable at December 31,	1 year 2 months 15 days
Aggregate Intrinsic Value (in thousands)
Outstanding at December 31		$0
Exercised during period	0
Exercisable at December 31	$0
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period

COMMON_STOCK_SARs_Fair_Value_A

COMMON STOCK SARs Fair Value Assumptions (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Rate	Rate	Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period
Stock Appreciation Rights (SARs) [Member]
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	6 years	6 years	6 years
Risk-free interest rate	2.10%	1.00%	1.10%
Expected Volatility	65.60%	65.50%	64.30%
Weighted-average grant date fair value per share	$29.96	$21.96	$17.61

COMMON_STOCK_Schedule_of_Chang1

COMMON STOCK Schedule of Changes in SARs (Details) (USD $)	12 Months Ended
COMMON STOCK Schedule of Changes in SARs (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Number of SARs
Outstanding beginning of year, January 1,	3,523	6,973	6,973
Exercised	0	-3,450	0
Outstanding end of year, December 31,	3,523	3,523	6,973
Exercisable at December 31,	3,523	3,523	6,973
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding beginning of year, January 1,	$44.95	$41.09	$41.09
Exercised	$0	$37.15	$0
Outstanding end of year, December 31,	$44.95	$44.95	$41.09
Exercisable at December 31,	$44.95	$44.95	$41.09
Weighted-Average Remaining Contractual Term (in years)
Outstanding at December 31,		2 years 2 months 12 days
Exercisable at December 31,	1 year 2 months 15 days
Share based compesation aggregate intrinsic valu [Roll Forward]
Outstanding beginning of year, January 1,		$0
Outstanding end of year, December 31,		0
Stock Appreciation Rights (SARs) [Member]
Number of SARs
Outstanding beginning of year, January 1,	190,763	118,832	50,471
Awarded	88,248	87,078	68,361
Exercised	0	-15,147	0
Outstanding end of year, December 31,	279,011	190,763	118,832
Exercisable at December 31,	139,334	51,922	27,458
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding beginning of year, January 1,	$33.77	$30.80	$31.61
Awarded	$49.57	$37.18	$30.19
Exercised	$0	$30.06	$0
Outstanding end of year, December 31,	$38.77	$33.77	$30.80
Exercisable at December 31,	$36.27	$29.97	$28.84
Weighted-Average Remaining Contractual Term (in years)
Outstanding at December 31,	7 years 9 months 20 days	8 years 2 months 0 days
Exercisable at December 31,	7 years 3 months 16 days
Share based compesation aggregate intrinsic valu [Roll Forward]
Outstanding beginning of year, January 1,	1,472,000	3,711,000	486,000	341,000
Awarded	0	0	0
Exercised	0	425,000	0
Outstanding end of year, December 31,	1,472,000	3,711,000	486,000	341,000
Exercisable at December 31,	982,000	1,207,000	187,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$2,300,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 8 months 13 days

COMMON_STOCK_Schedule_of_Chang2

COMMON STOCK Schedule of Changes in Restricted Stock - TIme Based Awards (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period
Number of Shares
Outstanding beginning of year, January 1,	3,523			6,973
Outstanding end of year, December 31,	3,523		6,973	6,973
Restricted Stock [Member]
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 or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed.
Time based shares granted to executives	104,467
Number of Shares
Outstanding beginning of year, January 1,	651,781
Granted	291,370
Vested	-328,071
Forfeited	-50,748
Outstanding end of year, December 31,	564,332	651,781
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	36.36
Weighted-average grant date fair value per share	56.45	$45.53	$26.59
Vested	36.26
Forfeited	45.04
Outstanding at end of year, December 31,	46.02	$36.36
Total intrinsic value of time based awards vested	18,278,000	$13,640,000	$5,950,000
Total intrinsic value of time-based awards non-vested	23,290,000	34,688,000	21,470,000
Market price per common share as of December 31,	41.27	$53.22	$33.21
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	17,000,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 9 months 13 days

COMMON_STOCK_Restricted_Stock_

COMMON STOCK Restricted Stock - Market Based Awards Fair Value Assumptions (Details) (Restricted Stock - Market Based Awards [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Rate	Rate	Dec. 31, 2012
Restricted Stock - Market Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term of award	3 years	3 years
Risk-free interest rate	0.80%	0.40%
Expected Volatility	55.20%	56.60%
Weighted-average grant date fair value per share	$56.87	$49.04	$36.54

COMMON_STOCK_Schedule_of_Chang3

COMMON STOCK Schedule of Changes in Restricted Stock - Market Based Awards (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period
Number of Shares
Outstanding beginning of year, January 1,	3,523			6,973
Outstanding end of year, December 31,	3,523		6,973	6,973
Restricted Stock - Market Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total intrinsic value of time based awards vested	1,260,000	$724,000	$0
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 five 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	42,151
Number of Shares
Outstanding beginning of year, January 1,	72,111
Granted	42,151
Vested	-30,541
Outstanding end of year, December 31,	83,721	72,111
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	43.75
Weighted-average grant date fair value per share	56.87	$49.04	$36.54
Vested	36.54
Outstanding at end of year, December 31,	52.98	$43.75
Total intrinsic value of market-based awards non-vested	3,455,000	3,838,000	1,352,000
Market price per common share as of December 31,	41.27	$53.22	$33.21
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	2,300,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 8 months 13 days

COMMON_STOCK_Treasury_Shares_D

COMMON STOCK Treasury Shares (Details) (Treasury Stock [Member])	12 Months Ended
	Dec. 31, 2014
Treasury Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury Stock, Shares, Acquired	97,646
Treasury Stock, Shares, Retired	703
Treasury stock acquired and reissued	83,208
Treasury stock acquired, and available for reissuance	13,735

COMMON_STOCK_Preferred_Stock_D

COMMON STOCK Preferred Stock (Details)	0 Months Ended
COMMON STOCK Preferred Stock (Details)	Jun. 23, 2008	Dec. 31, 2014	Dec. 31, 2013
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]
Equity Issuance, Date	23-Jun-08
Preferred Stock, Shares Authorized	50,000,000
Preferred Stock, Shares Issued		0

EARNINGS_PER_SHARE_Earnings_Pe

EARNINGS PER SHARE Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended			0 Months Ended
EARNINGS PER SHARE Earnings Per Share (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2010
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic	35,847,000	35,834,000	35,762,000	35,690,000	35,620,000	33,413,000	30,332,000	30,270,000	35,784,000	32,426,000	27,677,000
Weighted Average Number of Shares Outstanding - Diluted	36,146,000	36,828,000	35,762,000	35,690,000	36,836,000	33,413,000	31,014,000	30,270,000	36,678,000	32,426,000	27,677,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									34,000	1,424,000	820,000
Restricted Stock [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements									279,000	0	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									8,000	823,000	694,000
Stock Appreciation Rights [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements									45,000	0	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									26,000	72,000	116,000
Stock Options [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements									1,000	0	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									0	7,000	7,000
3.25% Convertible Note [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements									564,000	0	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									0	518,000	0
3.25% Convertible Senior Notes due 2016 [Member]
Convertible Senior Note Due 2016
Convertible Senior Note Principal Amount ($ per Note)												$1,000
3.25% Convertible Note, Number of Shares Convertible												2,700,000
3.25% Convertible Note, Conversion Price												$42.40
Non employee director deferred compensation [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements									5,000	0	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									0	4,000	3,000

ASSETS_HELD_FOR_SALE_DIVESTITU2

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Discontinued Operations and Disposal Groups (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Assets held for sale - current	$0				$7,661				$0	$7,661
Assets held for sale - non-current	2,874				182,136				2,874	182,136
Liabilities held for sale - current	0				12,069				0	12,069
Liabilities held for sale - non-current	0				55,915				0	55,915
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Impairment of Natural Gas and Crude Oil Properties									433	929	163,129
Income (loss) from discontinued operations, net of tax	47,782	-80	1,191	-719	-1,599	-2,093	4,047	-1,545	48,174	-1,190	-111,357
Supplemental Cash Flows Information
Capital expenditures									-628,592	-394,948	-347,729
Change in accounts payable related to purchases of properties and equipment									39,667	33,328	288
Net Assets Held for Sale
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Cash and Cash Equivalents	0				601				0	601
Other current assets	0				7,060				0	7,060
Assets held for sale - current	0				7,661				0	7,661
Properties and equipment	2,874				175,244				2,874	175,244
Other assets	0				6,892				0	6,892
Assets held for sale - non-current	2,874				182,136				2,874	182,136
Liabilities held for sale - current	0				12,069				0	12,069
Long-term debt	0				-52,000				0	-52,000
Asset retirement obligation	0				-2,234				0	-2,234
Other liabilities	0				1,681				0	1,681
Liabilities held for sale - non-current	0				55,915				0	55,915
Net assets	2,874				121,813				2,874	121,813
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	46,793
Sales from natural gas marketing									0	2,825	1,708
Commodity price risk management gain (loss), net									-1,085	14	3,060
Well operations, pipeline income and other									48	922	1,926
Disposal Group, Discontinued Operations, Total revenue									23,112	42,762	53,487
Production Costs									7,120	16,515	27,770
Cost of natural gas marketing									0	2,673	1,529
Impairment of Natural Gas and Crude Oil Properties									433	929	163,129
Depreciation, depletion and amortization									9,128	13,894	55,768
Accretion of ARO and other, Discontinued Operations									3,445	7,266	8,791
(Gain) loss on sale of properties and equipment									-76,479	1,700	-24,090
Total costs, expenses and other									-56,353	42,977	232,897
Disposal Group, Including Discontinued Operation, Interest Expense									-2,222	-1,755	-782
Disposal Group, Including Discontinued Operation, Interest Income									194	10	1
Income (loss) from discontinued operations									77,437	-1,960	-180,191
Income taxes (expense) benefit									-29,263	770	68,834
Income (loss) from discontinued operations, net of tax									48,174	-1,190	-111,357
PDCM Divestiture [Member]
Supplemental Cash Flows Information
Capital expenditures									-17,253	-45,277	-25,530
Change in accounts payable related to purchases of properties and equipment									($5,727)	($4,738)	($3,592)

ASSETS_HELD_FOR_SALE_DIVESTITU3

ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Additional Information (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 15, 2014	Sep. 30, 2014	Oct. 14, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Notes Receivable from sale of oil and gas properties	$39,707,000				$39,048,000
Shallow Upper Devonian Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas assets sale price before adjustments	20,600,000
Piceance and NECO Asset Group [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	177,600,000
Proceeds To NonAffiliated Investor Partners	17,000,000
Gain/loss on sale	-2,300,000
Segment, Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain/loss on sale	76,479,000	-1,700,000	24,090,000
Shallow Upper Devonian Letter of Credit [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Letters of Credit Outstanding, Amount ($)	6,700,000
Shallow Upper Devonian Sale [Member] \| PDCE proportionate share
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas assets sale price before adjustments	5,100,000
PDCM Divestiture [Member] \| PDCM Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners						50.00%
Gain/loss on sale				76,300,000
Divestiture Sale Price After Adjustment				192,000,000
Cash proceeds from PDCM divestiture				153,000,000
Promissory note				$39,000,000

ACQUISITIONS_Total_Identifiabl

ACQUISITIONS Total Identifiable Net Assets Acquired (Details) (Merit Acquisition [Member], USD $)	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2012
Merit Acquisition [Member]
Business Acquisition [Line Items]
Total acquisition cost	$304,643
Natural gas and crude oil properties - proved	180,696
Natural gas and crude oil properties - unproved	151,428
Other assets	3,631
Total assets acquired	335,755
Asset retirement obligation	14,833
Other accrued expenses	9,574
Other Liabilities	6,705
Total liabilities assumed	$31,112

ACQUISITIONS_Pro_Forma_Informa

ACQUISITIONS Pro Forma Information (Details) (Merit Acquisition [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012
Merit Acquisition [Member]
Business Acquisition, Pro Forma Information [Abstract]
Revenues	$370,488
Total costs, expenses and other	521,178
Net Income (Loss)	($119,343)
Basic	($4.31)
Diluted	($4.31)

TRANSACTIONS_WITH_AFFILIATES_A1

TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES Transactions with Affiliates and Other Related Parties (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Due from PDCM	$512,000	$6,614,000
PDCM
Related Party Transaction [Line Items]
Related party transactions included in cost of natural gas marketing	23,200,000	18,100,000	10,900,000
Well operating and administrative services on behalf of PDCM	5,700,000	14,500,000	12,100,000
Due from PDCM	0	4,600,000
Affiliated Partnerships
Related Party Transaction [Line Items]
Related party transactions included in cost of natural gas marketing		$1,300,000	$500,000

Recovered_Sheet1

BUSINESS SEGMENTS Business segments (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total revenues	$407,691	$224,556	$101,303	$122,657	$135,379	$71,815	$114,556	$70,915	$856,207	$392,665	$307,136
Segment income (loss) before income taxes	138,085	89,473	-48,028	-2,302	23,735	-23,342	25,315	-58,671	177,228	-32,963	-30,688
Expenditures for segment long-lived assets									628,592	404,606	659,952
Segment assets	2,340,588				2,025,203				2,340,588	2,025,203
Oil and Gas Properties
Segment Reporting Information [Line Items]
Total revenues									784,636	322,878	261,765
Segment income (loss) before income taxes									344,149	81,913	101,324
Expenditures for segment long-lived assets									623,912	403,227	656,443
Segment assets	2,254,751				1,751,106				2,254,751	1,751,106
Marketing
Segment Reporting Information [Line Items]
Total revenues									71,571	69,787	45,371
Segment income (loss) before income taxes									-445	-297	348
Segment assets	6,979				20,342				6,979	20,342
Corporate and Other
Segment Reporting Information [Line Items]
Segment income (loss) before income taxes									-166,476	-114,579	-132,360
Expenditures for segment long-lived assets									4,680	1,379	3,509
Segment assets	75,984				63,958				75,984	63,958
Assets Held-for-sale
Segment Reporting Information [Line Items]
Segment assets	$2,874				$189,797				$2,874	$189,797

BUSINESS_SEGMENTS_Additional_I

BUSINESS SEGMENTS Additional Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Crude oil and natural gas segment
Depreciation, depletion and amortization from continuing operations	$50,363	$49,640	$49,636	$42,889	$37,748	$26,957	$25,488	$25,431	$192,528	$115,624	$91,111
Oil and Gas Properties
Crude oil and natural gas segment
Depreciation, depletion and amortization from continuing operations									$188,500	$111,600	$86,300

SUPPLEMENTAL_INFORMATION_NATUR2

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Prices Used to Estimate Reserves (Unaudited) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Crude Oil (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	$84.65	$82.18	$87.51
Natural Gas (Mcf)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	3.92	3.22	2.35
Natural Gas Liquids (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	$32.27	$29.92	$28.02

SUPPLEMENTAL_INFORMATION_NATUR3

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Changes in Estimated Proved Reserves (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	bbl	bbl		bbl		bbl
Reserve Quantities [Line Items]
Proved Reserves	250,129,000	265,774,000		192,810,000		169,248,000
Undeveloped Reserves Converted to Developed	0	0		0
Revisions of Previous Estimates	-64,825,000	-46,480,000		-58,639,000
Extensions, Discoveries, and Other Additions	98,029,000	141,935,000		67,941,000
Purchases of Reserves	17,000	1,043,000		33,420,000
Dispositions	-39,572,000	-16,104,000		-10,891,000
Production	-9,294,000	-7,430,000		-8,269,000
Crude Oil (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	100,515,000	93,830,000	[1]	59,310,000	[2]	37,636,000	[3]
Revisions of Previous Estimates	-29,777,000	-18,420,000		-6,729,000
Extensions, Discoveries, and Other Additions	40,792,000	55,759,000		27,482,000
Purchases of Reserves	5,000	343,000		10,801,000
Dispositions	-13,000	-252,000		-7,854,000
Production	-4,322,000	-2,910,000		-2,026,000
Proved Developed Reserves	26,798,000	23,997,000	[1]	20,412,000	[2]	16,910,000	[3]
Proved Undeveloped Reserve	73,717,000	69,833,000	[1]	38,898,000	[2]	20,726,000	[3]
Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves	536,972,000	739,640,000	[1]	604,038,000	[2]	672,145,000	[3]
Revisions of Previous Estimates	-149,064,000	-117,068,000		-289,436,000
Extensions, Discoveries, and Other Additions	202,957,000	365,563,000		172,933,000
Purchases of Reserves	43,000	2,894,000		87,212,000
Dispositions	-237,306,000	-94,927,000		-6,406,000
Production	-19,298,000	-20,860,000		-32,410,000
Proved Developed Reserves	186,633,000	220,387,000	[1]	281,925,000	[2]	299,369,000	[3]
Proved Undeveloped Reserve	350,339,000	519,253,000	[1]	322,113,000	[2]	372,776,000	[3]
Natural Gas Liquids (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	60,119,000	48,671,000	[1]	32,827,000	[2]	19,588,000	[3]
Revisions of Previous Estimates	-10,204,000	-8,549,000		-3,671,000
Extensions, Discoveries, and Other Additions	23,411,000	25,249,000		11,637,000
Purchases of Reserves	5,000	217,000		8,084,000
Dispositions	-8,000	-30,000		-1,970,000
Production	-1,756,000	-1,043,000		-841,000
Proved Developed Reserves	17,002,000	14,825,000	[1]	14,353,000	[2]	11,753,000	[3]
Proved Undeveloped Reserve	43,117,000	33,846,000	[1]	18,474,000	[2]	7,835,000	[3]
Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves	250,129,000	265,774,000	[1]	192,810,000	[2]	169,248,000	[3]
Revisions of Previous Estimates	-64,825,000	-46,480,000		-58,639,000
Extensions, Discoveries, and Other Additions	98,029,000	141,935,000		67,941,000
Purchases of Reserves	17,000	1,043,000		33,420,000
Dispositions	-39,572,000	-16,104,000		-10,891,000
Production	-9,294,000	-7,430,000		-8,269,000
Proved Developed Reserves	74,905,000	75,553,000	[1]	81,753,000	[2]	78,558,000	[3]
Proved Undeveloped Reserve	175,224,000	190,221,000	[1]	111,058,000	[2]	90,690,000	[3]
Permian Asset Group \| Crude Oil (Bbls)
Reserve Quantities [Line Items]
Proved Reserves						7,825,000	[3]
Proved Developed Reserves						1,815,000	[3]
Proved Undeveloped Reserve						6,010,000	[3]
Permian Asset Group \| Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves						6,242,000	[3]
Proved Developed Reserves						1,750,000	[3]
Proved Undeveloped Reserve						4,492,000	[3]
Permian Asset Group \| Natural Gas Liquids (Bbls)
Reserve Quantities [Line Items]
Proved Reserves						1,970,000	[3]
Proved Developed Reserves						550,000	[3]
Proved Undeveloped Reserve						1,420,000	[3]
Permian Asset Group \| Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves						10,835,000	[3]
Proved Developed Reserves						2,657,000	[3]
Proved Undeveloped Reserve						8,179,000	[3]
Piceance and NECO Asset Group [Member] \| Crude Oil (Bbls)
Reserve Quantities [Line Items]
Proved Developed Reserves				148,000	[3]
Piceance and NECO Asset Group [Member] \| Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Developed Reserves				83,656,000	[3]
Piceance and NECO Asset Group [Member] \| Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Developed Reserves				14,091,000	[3]
Marcellus Shale Asset Group \| Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves		235,950,000	[3]
Proved Developed Reserves		53,904,000	[3]
Proved Undeveloped Reserve		182,046,000	[3]
Marcellus Shale Asset Group \| Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves		39,325,000	[3]
Proved Developed Reserves		8,984,000	[3]
Proved Undeveloped Reserve		30,341,000	[3]
Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Proved Reserves	74,905,000	75,553,000		81,753,000		78,558,000
Undeveloped Reserves Converted to Developed	12,730,000	3,212,000		7,655,000
Revisions of Previous Estimates	-22,827,000	-6,751,000		-18,318,000
Extensions, Discoveries, and Other Additions	27,957,000	19,830,000		11,298,000
Purchases of Reserves	17,000	1,043,000		13,542,000
Dispositions	-9,231,000	-16,104,000		-2,713,000
Production	-9,294,000	-7,430,000		-8,269,000
Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved Reserves	175,224,000	190,221,000		111,057,000		90,690,000
Undeveloped Reserves Converted to Developed	-12,730,000	-3,212,000		-7,655,000
Revisions of Previous Estimates	-41,998,000	-39,729,000		-40,321,000
Extensions, Discoveries, and Other Additions	70,072,000	122,105,000		56,643,000
Purchases of Reserves	0	0		19,878,000
Dispositions	-30,341,000	0		-8,178,000
Production	0	0		0

[1]	Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 14, 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 14, 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.
[3]	Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian assets. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively.

SUPPLEMENTAL_INFORMATION_NATUR4

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Schedule of Developed and Undeveloped Reserves (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2011
	bbl	bbl		bbl		Rate	Rate	Rate	Rate	Rate	bbl
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	250,129,000	265,774,000		192,810,000							169,248,000
Undeveloped Reserves Converted to Developed	0	0		0
Revisions of Previous Estimates	-64,825,000	-46,480,000		-58,639,000
Extensions, Discoveries, and Other Additions	98,029,000	141,935,000		67,941,000
Purchases of Reserves	17,000	1,043,000		33,420,000
Dispositions	-39,572,000	-16,104,000		-10,891,000
Production	-9,294,000	-7,430,000		-8,269,000
Crude Oil Equivalent (Boe)
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	250,129,000	265,774,000	[1]	192,810,000	[2]						169,248,000	[3]
Revisions of Previous Estimates	-64,825,000	-46,480,000		-58,639,000
Extensions, Discoveries, and Other Additions	98,029,000	141,935,000		67,941,000
Purchases of Reserves	17,000	1,043,000		33,420,000
Dispositions	-39,572,000	-16,104,000		-10,891,000
Production	-9,294,000	-7,430,000		-8,269,000
Year-over-Year Activity [Domain]
Schedule of Developed and Undeveloped Reserves [Line Items]
Revisions of Previous Estimates	-65,000,000	46,000,000		59,000,000
Extensions, Discoveries, and Other Additions	98,000,000	142,000,000		68,000,000
Purchases of Reserves		1,000,000		33,000,000
Dispositions	-40,000,000	-16,000,000		-11,000,000
Increase (decrease) in proved reserves	-16,000,000
Majority of downward revision of our previous estimate of proved reserves	-69,000,000	-55,000,000
Change in drilling plans	-55,000,000
Downward revisions due to adjustments in previous PUD well spacing plans	-2,000,000	-32,000,000
Downward revisions in reserves due to abandoned leases	-1,000,000	-9,000,000
Downward revisions in reserves due to our shift from vertical to horizontal drilling		-11,000,000
Downward revisions Wattenberg Field related to PUDs that are no longer in our core drilling area	-8,000,000	-3,000,000
Downward revision in reserves due to increase in operating costs	-3,000,000			-1,000,000
Revisions due to asset performance	-2,000,000	2,000,000		2,000,000
Revision in reserves due to production from uneconomic or divested wells	2,000,000	2,000,000
Revisions due to change in commodity pricing	1,000,000	1,000,000		-40,000,000
Asset performance Wattenberg field	1,000,000
Reserve discoveries from non-PUD drilling	16,000,000	17,000,000
Extension and discoveries from new proved undeveloped reserves	96,000,000	125,000,000
Extension and discoveries due to adjustments in wells spacing in Wattenberg Field and Marcellus Shale	78,000,000	32,000,000
Extension and discoveries in the Marcellus Shale		18,000,000
Extension and discoveries in the Utica Shale	2,000,000	14,000,000
Reserve discoveries, refracs not added in prior year report	2,000,000
Adjustments for geological reasons				-8,000,000
Revision due to SEC 5 Year Rule				-13,000,000
Revisions due to interest adjustments		3,000,000		500,000
Reserve discoveries, Eastern Operating Region				10,000,000
Reserve discoveries, Wattenberg Field	96,000,000	110,000,000		59,000,000
Development Wells Drilled, Net Productive				0
PUD conversion rate	7.00%					16.00%	19.00%	22.00%	27.00%	16.00%
Developed [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	74,905,000	75,553,000		81,753,000							78,558,000
Undeveloped Reserves Converted to Developed	12,730,000	3,212,000		7,655,000
Revisions of Previous Estimates	-22,827,000	-6,751,000		-18,318,000
Extensions, Discoveries, and Other Additions	27,957,000	19,830,000		11,298,000
Purchases of Reserves	17,000	1,043,000		13,542,000
Dispositions	-9,231,000	-16,104,000		-2,713,000
Production	-9,294,000	-7,430,000		-8,269,000
Undeveloped [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	175,224,000	190,221,000		111,057,000							90,690,000
Undeveloped Reserves Converted to Developed	-12,730,000	-3,212,000		-7,655,000
Revisions of Previous Estimates	-41,998,000	-39,729,000		-40,321,000
Extensions, Discoveries, and Other Additions	70,072,000	122,105,000		56,643,000
Purchases of Reserves	0	0		19,878,000
Dispositions	-30,341,000	0		-8,178,000
Production	0	0		0

[1]	Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 14, 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 14, 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.
[3]	Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian assets. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively.

SUPPLEMENTAL_INFORMATION_NATUR5

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Results of Operations for Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Natural gas, NGL and crude oil sales	$495,562	$379,796	$274,783
Commodity price risk management	309,219	-23,905	32,339
Total Revenues from Oil and Gas Producing Activities	804,781	355,891	307,122
Production Costs	90,744	81,365	77,537
Exploration Expense	948	7,071	22,605
Impairment of Oil and Gas Properties	163,965	53,438	162,287
Depreciation, Depletion and Amortization	201,656	124,202	146,879
Accretion of Asset Retirement Obligations	3,455	4,747	4,060
(Gain) loss on Sale of Properties and Equipment	-75,972	3,722	-24,273
Total Expense from Oil and Gas Producing Activities	384,796	274,545	389,095
Results of Operations of Natural Gas and Crude Oil Producing Activities, Income before Income Taxes	419,985	81,346	-81,973
Provision for Income Taxes	-163,647	-29,400	31,163
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs	$256,338	$51,946	($50,810)

SUPPLEMENTAL_INFORMATION_NATUR6

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 $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved Properties	$11,973,000	[1]	$28,698,000	[1]	$105,303,000	[1]
Unproved Properties	45,999,000	[1]	3,390,000	[1]	276,225,000	[1]
Development Costs	590,855,000	[2]	332,250,000	[2]	233,144,000	[2]
Exploratory drilling	0	[3]	58,988,000	[3]	18,803,000	[3]
Geological and geophysical	1,000	[3]	752,000	[3]	1,925,000	[3]
Total Costs Incurred	648,828,000		424,078,000		635,400,000
Cost Incurred to Convert PUDs to PDNP	$125,200,000		$40,100,000		$62,000,000

[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 DecemberB 31, 2014, 2013 and 2012, $125.2 million, $40.1 million and $62.0 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_NATUR7

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved natural gas and crude oil properties	$2,267,165	$1,677,271
Unproved natural gas and crude oil properties	188,206	253,463
Uncompleted Wells, Equipment and Facilities	137,134	40,745
Capitalized Costs	2,592,505	1,971,479
Less accumulated DD&A	-808,431	-507,510
Capitalized Costs, Net	$1,784,074	$1,463,969

SUPPLEMENTAL_INFORMATION_NATUR8

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Unaudited) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Estimated Cash Flows	$12,550,515	$11,550,917	$7,529,292
Future Estimated Production Costs	-2,816,776	-2,329,836	-1,690,453
Future Estimated Development Costs	-2,458,790	-2,778,148	-1,852,177
Future Estimated Income Tax Expense	-2,336,510	-2,119,615	-1,230,294
Future Net Cash Flows	4,938,439	4,323,318	2,756,368
10% Annual Discount for Estimated Timing of Cash Flows	-2,631,974	-2,541,155	-1,587,871
Standardized Measure of Disconted Future Estimated Net Cash Flows	$2,306,465	$1,782,163	$1,168,497

SUPPLEMENTAL_INFORMATION_NATUR9

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, 2014		Dec. 31, 2013		Dec. 31, 2012
	Rate		Rate		Rate
Principal Sources of Change:
Sales of natural gas, NGL and crude oil production, net of production costs	($387,789,000)		($286,021,000)		($194,346,000)
Net changes in prices and production costs	129,213,000	[1]	89,527,000	[1]	95,501,000	[1]
Extensions, discoveries and improved recovery, less related costs	1,444,581,000	[2]	1,529,006,000	[2]	632,781,000	[2]
Sales of reserves	-402,595,000	[3]	-142,724,000	[3]	-86,902,000	[3]
Purchases of reserves	238,000	[4]	10,610,000	[4]	296,208,000	[4]
Development costs incurred during the period	161,404,000		46,366,000		69,198,000
Revisions of previous quantity estimates	-654,318,000	[5]	-397,738,000	[5]	-452,775,000	[5]
Changes in estimated income taxes	-221,874,000	[6]	-381,369,000	[6]	-131,256,000	[6]
Net change in future development costs	46,499,000		-40,707,000		-3,979,000
Accretion of discount	270,389,000		142,040,000		124,105,000
Timing and other	138,554,000		44,676,000		-121,247,000
Total	524,302,000		613,666,000		227,288,000
Notes to Changes in SMOG [Abstract]
Weighted-Average price, net of production cost	$37.78		$30.82		$30.28
Percentage Change in Extensions and Discoveries	-6.00%		142.00%
Long-Term Deferred Tax Rate	38.00%		38.00%		38.20%

[1]	Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to $37.78 as compared to $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. Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $30.82 from $30.28 in our 2012 report due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which increased our liquids as a percentage of proved reserves.
[2]	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. The 142% increase in 2013 as compared to 2012 is primarily due to the addition of PUDs in the Utica Shale and our continued focus on our Wattenberg Field drilling program. Our increased PUD count in the Wattenberg Field is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report.
[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. The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013.
[4]	The decrease in purchases of reserves in 2014 and 2013 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 2014 as compared to 2013 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule.
[6]	The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38%, 38% and 38.2% for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital.

SUPPLEMENTAL_INFORMATION_QUART1

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Natural gas, NGL and crude oil sales	$99,857	$120,526	$131,017	$120,013	$113,810	$77,340	$73,695	$75,950	$471,413	$340,795	$227,990
Sales from natural gas marketing	8,922	13,297	22,415	26,937	21,092	16,946	18,079	13,670	71,571	69,787	45,371
Commodity price risk management gain (loss), net	297,643	90,213	-52,643	-24,909	-1,844	-24,138	21,828	-19,765	310,304	-23,919	29,279
Well operations, pipeline income and other	1,269	520	514	616	2,321	1,667	954	1,060	2,919	6,002	4,496
Total revenues	407,691	224,556	101,303	122,657	135,379	71,815	114,556	70,915	856,207	392,665	307,136
Costs, expenses and other:
Production costs	19,013	22,754	23,774	18,083	19,159	17,036	14,274	14,381	83,624	64,850	49,383
Cost of natural gas marketing	9,370	13,347	22,428	26,870	21,156	17,127	18,065	13,736	72,015	70,084	45,023
Exploration expense	174	190	276	307	1,687	1,841	1,266	1,540	947	6,334	18,202
Impairment of natural gas and crude oil properties	159,911	1,863	848	910	715	4,236	1,298	46,260	163,532	52,509	5,020
General and administrative expense	19,310	34,625	39,440	22,484	16,018	15,052	14,849	14,037	115,859	59,956	54,817
Depreciation, depletion and amortization	50,363	49,640	49,636	42,889	37,748	26,957	25,488	25,431	192,528	115,624	91,111
Accretion of asset retirement obligations	873	861	840	841	1,075	1,181	1,167	1,143	3,415	4,566	3,670
(Gain) loss on sale of Leaseholds	-70	21	-23	579	2,153	-100	-1	-30	507	2,022	-183
Total cost, expenses and other	258,944	123,301	137,219	112,963	99,711	83,330	76,406	116,498	632,427	375,945	267,043
Income from operations	148,747	101,255	-35,916	9,694	35,668	-11,515	38,150	-45,583	223,780	16,720	40,093
Loss on extinguishment of debt									0	0	-23,283
Interest expense	-11,643	-11,821	-12,195	-12,183	-12,260	-11,957	-12,838	-13,088	-47,842	-50,143	-47,505
Interest income	981	39	83	187	327	130	3	0	1,290	460	7
Income (loss) from continuing operations before income taxes	138,085	89,473	-48,028	-2,302	23,735	-23,342	25,315	-58,671	177,228	-32,963	-30,688
Provision for income taxes	-54,115	-35,396	18,650	894	-8,937	9,435	-9,444	20,798	-69,967	11,852	11,333
Income (loss) from continuing operations	83,970	54,077	-29,378	-1,408	14,798	-13,907	15,871	-37,873	107,261	-21,111	-19,355
Income (loss) from discontinued operations, net of tax	47,782	-80	1,191	-719	-1,599	-2,093	4,047	-1,545	48,174	-1,190	-111,357
Net income (loss)	$131,752	$53,997	($28,187)	($2,127)	$13,199	($16,000)	$19,918	($39,418)	$155,435	($22,301)	($130,712)
Basic
Income (loss) from continuing operations	$2.34	$1.51	($0.82)	($0.04)	$0.42	($0.42)	$0.53	($1.25)	$3	($0.65)	($0.70)
Income (loss) from discontinued operations	$1.33	$0	$0.03	($0.02)	($0.04)	($0.06)	$0.13	($0.05)	$1.34	($0.04)	($4.02)
Net income (loss) attributable to shareholders	$3.67	$1.51	($0.79)	($0.06)	$0.38	($0.48)	$0.66	($1.30)	$4.34	($0.69)	($4.72)
Diluted
Income (loss) from continuing operations	$2.32	$1.47	($0.82)	($0.04)	$0.40	($0.42)	$0.51	($1.25)	$2.93	($0.65)	($0.70)
Income (loss) from discontinued operations	$1.32	$0	$0.03	($0.02)	($0.04)	($0.06)	$0.13	($0.05)	$1.31	($0.04)	($4.02)
Net income (loss) attributable to shareholders	$3.64	$1.47	($0.79)	($0.06)	$0.36	($0.48)	$0.64	($1.30)	$4.24	($0.69)	($4.72)
Weighted-average common shares outstanding
Basic	35,847	35,834	35,762	35,690	35,620	33,413	30,332	30,270	35,784	32,426	27,677
Diluted	36,146	36,828	35,762	35,690	36,836	33,413	31,014	30,270	36,678	32,426	27,677

SCHEDULE_II_VALUATION_AND_QUAL

SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for Doubtful Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1	$896		$718		$644
Charged to Cost and Expense	78		322		222
Deductions	488	[1]	144	[1]	148	[1]
Ending Balance, December 31	486		896		718
Valuation Allowance for Unproved Natural Gas and Crude Oil Properties [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1	5,142		5,690		10,711
Charged to Cost and Expense	4,465		3,038		3,332
Deductions	314	[1]	3,586	[1]	8,353	[1]
Ending Balance, December 31	$9,293		$5,142		$5,690

[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.

Uncategorized_Items

Uncategorized Items
[us-gaap_SharesIssued]	23,634,958	2,938