Gastar Exploration (GST) 10-K 13 Mar 14 2013 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Mar. 11, 2014	Jun. 28, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Entity Registrant Name	'Gastar Exploration Inc.	'	'
Entity Central Index Key	'0001431372	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Accelerated Filer	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$157.10
Entity Common Stock, Shares Outstanding	'	61,889,655	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$32,393	$8,901
Accounts receivable, net of allowance for doubtful accounts of $507 and $546, respectively	21,656	9,540
Commodity derivative contracts	0	7,799
Prepaid expenses	1,145	1,097
Total current assets	55,194	27,337
Oil and natural gas properties, full cost method of accounting:	'	'
Unproved properties, excluded from amortization	96,220	67,892
Proved properties	935,773	671,193
Total oil and natural gas properties	1,031,993	739,085
Furniture and equipment	2,691	1,925
Total property, plant and equipment	1,034,684	741,010
Accumulated depreciation, depletion and amortization	-517,171	-484,759
Total property, plant and equipment, net	517,513	256,251
OTHER ASSETS:	'	'
Commodity derivative contracts	7,545	1,369
Deferred charges, net	2,950	836
Advances to operators and other assets	6,733	4,275
Total other assets	17,228	6,480
TOTAL ASSETS	589,935	290,068
CURRENT LIABILITIES:	'	'
Accounts payable	11,046	23,863
Revenue payable	12,514	8,801
Accrued interest	3,504	151
Accrued drilling and operating costs	8,756	3,907
Advances from non-operators	9,259	17,540
Commodity derivative contracts	3,403	1,399
Commodity derivative premium payable	145	0
Asset retirement obligation	633	358
Other accrued liabilities	4,844	1,493
Total current liabilities	54,104	57,512
LONG-TERM LIABILITIES:	'	'
Long-term debt	312,994	98,000
Commodity derivative contracts	378	1,304
Commodity derivative premium payable	7,000	0
Asset retirement obligation	5,430	6,605
Other long-term liabilities	0	111
Total long-term liabilities	325,802	106,020
Commitments and contingencies (Note 14)	'	'
STOCKHOLDERS' EQUITY:	'	'
Common stock	61	316,346
Additional paid-in capital	337,969	28,336
Accumulated deficit	-254,823	-294,787
Total stockholders' equity	83,207	49,895
Non-controlling interest:	'	'
Preferred stock of subsidiary, aggregate liquidation preference $152,454 and $98,781 at December 31, 2013 and 2012, respectively	126,822	76,641
Total equity	210,029	126,536
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	589,935	290,068
Gastar Exploration USA Inc.	'	'
CURRENT ASSETS:	'	'
Cash and cash equivalents	32,379	8,892
Accounts receivable, net of allowance for doubtful accounts of $507 and $546, respectively	21,650	9,539
Commodity derivative contracts	0	7,799
Prepaid expenses	946	919
Total current assets	54,975	27,149
Oil and natural gas properties, full cost method of accounting:	'	'
Unproved properties, excluded from amortization	96,220	67,892
Proved properties	935,765	671,185
Total oil and natural gas properties	1,031,985	739,077
Furniture and equipment	2,691	1,925
Total property, plant and equipment	1,034,676	741,002
Accumulated depreciation, depletion and amortization	-517,164	-484,752
Total property, plant and equipment, net	517,512	256,250
OTHER ASSETS:	'	'
Commodity derivative contracts	7,545	1,369
Deferred charges, net	2,950	836
Advances to operators and other assets	6,733	4,275
Total other assets	17,228	6,480
TOTAL ASSETS	589,715	289,879
CURRENT LIABILITIES:	'	'
Accounts payable	11,031	23,863
Revenue payable	12,514	8,801
Accrued interest	3,504	151
Accrued drilling and operating costs	8,756	3,907
Advances from non-operators	9,259	17,540
Commodity derivative contracts	3,403	1,399
Commodity derivative premium payable	145	0
Asset retirement obligation	633	358
Other accrued liabilities	4,794	1,480
Total current liabilities	54,039	57,499
LONG-TERM LIABILITIES:	'	'
Long-term debt	312,994	98,000
Commodity derivative contracts	378	1,304
Commodity derivative premium payable	7,000	0
Asset retirement obligation	5,423	6,598
Other long-term liabilities	0	111
Due to parent	34,337	30,903
Total long-term liabilities	360,132	136,916
Commitments and contingencies (Note 14)	'	'
STOCKHOLDERS' EQUITY:	'	'
Common stock	0	237,431
Additional paid-in capital	352,192	76,601
Accumulated deficit	-176,709	-218,608
Total stockholders' equity	175,544	95,464
Non-controlling interest:	'	'
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	589,715	289,879
Gastar Exploration USA Inc. | Series A Preferred Stock	'	'
STOCKHOLDERS' EQUITY:	'	'
Preferred stock	40	40
Gastar Exploration USA Inc. | Series B Preferred Stock	'	'
STOCKHOLDERS' EQUITY:	'	'
Preferred stock	$21	$0

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013
Accounts receivable, doubtful accounts	$546	$507
Common stock, par value	'	$0.00
Common stock, no par value	$0	'
Common stock, shares authorized	'unlimited	'
Common stock, shares issued	66,432,609	61,211,658
Common stock, shares outstanding	66,432,609	61,211,658
Preferred stock of subsidiary, aggregate liquidation preference	98,781	152,454
Preferred stock, par value	'	$0.01
Preferred stock, shares authorized	'	40,000,000
Common stock, shares authorized	'	275,000,000
Gastar Exploration USA Inc.	'	'
Accounts receivable, doubtful accounts	$546	$507
Common stock, par value	'	$0.00
Common stock, shares issued	750	750
Common stock, shares outstanding	750	750
Common stock, shares authorized	1,000	275,000,000
Series A Preferred Stock | Gastar Exploration USA Inc.	'	'
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	3,951,254	3,958,160
Preferred stock, shares outstanding	3,951,254	3,958,160
Preferred Stock, liquidation preference per share	$25	$25
Series B Preferred Stock | Gastar Exploration USA Inc.	'	'
Preferred stock, par value	'	$0.01
Preferred stock, shares authorized	'	10,000,000
Preferred stock, shares issued	'	2,140,000
Preferred stock, shares outstanding	'	2,140,000
Preferred Stock, liquidation preference per share	$25	$25

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:	'	'	'
Natural gas	$40,416	$23,318	$23,523
Oil and condensate	36,480	11,570	3,416
NGLs	15,611	7,630	1,092
Total natural gas, oil and condensate and NGLs revenues	92,507	42,518	28,031
(Loss) gain on commodity derivatives contracts	-4,752	7,422	12,204
Total revenues	87,755	49,940	40,235
EXPENSES:	'	'	'
Production taxes	4,651	2,269	620
Lease operating expenses	9,456	6,174	8,630
Transportation, treating and gathering	4,006	4,965	4,501
Depreciation, depletion and amortization	32,449	25,424	15,216
Impairment of natural gas and oil properties	0	150,787	0
Accretion of asset retirement obligation	468	388	534
General and administrative expense	16,961	12,211	11,365
Litigation settlement expense	1,000	1,250	0
Total expenses	68,991	203,468	40,866
INCOME (LOSS) FROM OPERATIONS	18,764	-153,528	-631
OTHER INCOME (EXPENSE):	'	'	'
Gain on acquisition of assets at fair value	27,670	0	0
Interest expense	-13,168	-270	-113
Investment and other income	48	9	10
Foreign transaction loss	-14	-2	-6
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES	33,300	-153,791	-740
Income tax benefit	-16,042	0	0
NET INCOME (LOSS)	49,342	-153,791	-740
Dividends on preferred stock attributable to non-controlling interest	-9,378	-7,077	-1,024
NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION, INC.	39,964	-160,868	-1,764
NET INCOME (LOSS) PER SHARE OF COMMON STOCK ATTRIBUTABLE TO GASTAR EXPLORATION, INC. COMMON STOCKHOLDERS:	'	'	'
Basic (in dollars per share)	$0.66	($2.53)	($0.03)
Diluted (in dollars per share)	$0.63	($2.53)	($0.03)
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:	'	'	'
Basic (shares)	60,220,115	63,538,362	63,003,579
Diluted (shares)	63,618,401	63,538,362	63,003,579
Gastar Exploration USA Inc.	'	'	'
REVENUES:	'	'	'
Natural gas	40,416	23,318	23,523
Oil and condensate	36,480	11,570	3,416
NGLs	15,611	7,630	1,092
Total natural gas, oil and condensate and NGLs revenues	92,507	42,518	28,031
(Loss) gain on commodity derivatives contracts	-4,752	7,422	12,204
Total revenues	87,755	49,940	40,235
EXPENSES:	'	'	'
Production taxes	4,651	2,269	620
Lease operating expenses	9,456	6,174	8,629
Transportation, treating and gathering	4,006	4,965	4,501
Depreciation, depletion and amortization	32,449	25,424	15,216
Impairment of natural gas and oil properties	0	150,787	0
Accretion of asset retirement obligation	468	388	534
General and administrative expense	15,153	10,732	10,434
Litigation settlement expense	1,000	1,250	0
Total expenses	67,183	201,989	39,934
INCOME (LOSS) FROM OPERATIONS	20,572	-152,049	301
OTHER INCOME (EXPENSE):	'	'	'
Gain on acquisition of assets at fair value	27,670	0	0
Interest expense	-13,016	-271	-112
Investment and other income	20	-4	95
Foreign transaction loss	-11	2	1
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES	35,235	-152,322	285
Income tax benefit	-16,042	0	0
NET INCOME (LOSS)	51,277	-152,322	285
Dividends on preferred stock	-9,378	-7,077	-1,024
NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION, INC.	$41,899	($159,399)	($739)

Consolidated_Statement_of_Stoc

Consolidated Statement of Stockholders' Equity (USD $)

Total

Common Stock

Additional Paid-in Capital

Accumulated Deficit

Total Gastar Exploration, Inc. Stockholdersb Equity

Non-controlling Interest

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

In Thousands, except Share data, unless otherwise specified

Series B Preferred Stock

Common Stock

Additional Paid-in Capital

Accumulated Deficit

Preferred Stock

Preferred Stock

Series A Preferred Stock

Series B Preferred Stock

Balance at beginning of period at Dec. 31, 2010

'

'

'

'

'

'

$181,961

'

$240,431

$0

($58,470)

$0

'

Balance at beginning of period at Dec. 31, 2010

207,391

316,346

23,200

-132,155

207,391

0

'

'

'

'

'

'

'

Balance at beginning of period (in shares) at Dec. 31, 2010

'

64,179,115

'

'

'

'

'

'

750

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution to Parent

'

'

'

'

'

'

-1,000

'

-1,000

0

0

'

'

Net income (loss)

-740

'

'

'

'

'

285

'

0

0

285

'

'

Issuance of preferred stock (shares)

'

'

'

'

'

'

'

'

'

'

'

1,364,543

'

Issuance of preferred stock

'

'

'

'

'

'

27,391

'

0

27,377

0

14

'

Preferred stock dividends

'

'

'

'

'

'

-1,024

'

0

0

-1,024

'

'

Issuance of restricted stock, net of forfeitures (shares)

'

524,337

'

'

'

'

'

'

'

'

'

'

'

Issuance of restricted stock, net of forfeitures

-436

0

-436

0

-436

0

'

'

'

'

'

'

'

Exercise of stock options, net of forfeitures (shares)

'

3,298

'

'

'

'

'

'

'

'

'

'

'

Exercise of stock options, net of forfeitures

0

0

0

0

0

0

'

'

'

'

'

'

'

Stock based compensation

2,612

0

2,612

0

2,612

0

'

'

'

'

'

'

'

Net loss

-1,764

0

0

-1,764

-1,764

0

'

'

'

'

'

'

'

Issuance of preferred stock of subsidiary

27,391

0

0

0

0

27,391

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2011

235,194

316,346

25,376

-133,919

207,803

27,391

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2011

'

'

'

'

'

'

207,613

'

239,431

27,377

-59,209

14

'

Balance at end of period (in shares) at Dec. 31, 2011

'

64,706,750

'

'

'

'

'

'

750

'

'

1,364,543

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income (loss)

-5,074

'

'

'

'

'

-4,686

'

'

'

'

'

'

Net loss

-6,310

'

'

'

'

'

-5,922

'

'

'

'

'

'

Balance at end of period at Mar. 31, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at beginning of period at Dec. 31, 2011

'

'

'

'

'

'

207,613

'

239,431

27,377

-59,209

14

'

Balance at beginning of period at Dec. 31, 2011

235,194

316,346

25,376

-133,919

207,803

27,391

'

'

'

'

'

'

'

Balance at beginning of period (in shares) at Dec. 31, 2011

'

64,706,750

'

'

'

'

'

'

750

'

'

1,364,543

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution to Parent

'

'

'

'

'

'

-2,000

'

-2,000

0

0

'

'

Net income (loss)

-153,791

'

'

'

'

'

-152,322

'

0

0

-152,322

'

'

Issuance of preferred stock (shares)

'

'

'

'

'

'

'

'

'

'

'

2,586,711

'

Issuance of preferred stock

'

'

'

'

'

'

49,250

'

0

49,224

0

26

'

Preferred stock dividends

'

'

'

'

'

'

-7,077

'

0

0

-7,077

'

'

Issuance of restricted stock, net of forfeitures (shares)

'

1,725,252

'

'

'

'

'

'

'

'

'

'

'

Issuance of restricted stock, net of forfeitures

-335

0

-335

0

-335

0

'

'

'

'

'

'

'

Exercise of stock options, net of forfeitures (shares)

'

607

'

'

'

'

'

'

'

'

'

'

'

Exercise of stock options, net of forfeitures

0

0

0

0

0

0

'

'

'

'

'

'

'

Stock based compensation

3,295

0

3,295

0

3,295

0

'

'

'

'

'

'

'

Net loss

-160,868

0

0

-160,868

-160,868

0

'

'

'

'

'

'

'

Issuance of preferred stock of subsidiary

49,250

0

0

0

0

49,250

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2012

126,536

316,346

28,336

-294,787

49,895

76,641

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2012

49,895

'

'

'

'

'

95,464

'

237,431

76,601

-218,608

40

'

Balance at end of period (in shares) at Dec. 31, 2012

'

66,432,609

'

'

'

'

'

'

750

'

'

3,951,254

'

Balance at beginning of period at Sep. 30, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income (loss)

5,064

'

'

'

'

'

5,382

'

'

'

'

'

'

Net loss

2,934

'

'

'

'

'

3,252

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2012

126,536

'

'

'

'

'

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2012

49,895

'

'

'

'

'

95,464

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income (loss)

-2,456

'

'

'

'

'

-2,231

'

'

'

'

'

'

Net loss

-4,586

'

'

'

'

'

-4,361

'

'

'

'

'

'

Balance at end of period at Mar. 31, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at beginning of period at Dec. 31, 2012

49,895

'

'

'

'

'

95,464

'

237,431

76,601

-218,608

40

'

Balance at beginning of period at Dec. 31, 2012

126,536

316,346

28,336

-294,787

49,895

76,641

'

'

'

'

'

'

'

Balance at beginning of period (in shares) at Dec. 31, 2012

'

66,432,609

'

'

'

'

'

'

750

'

'

3,951,254

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution to Parent

'

'

'

'

'

'

-12,000

'

-12,000

0

0

'

'

Net income (loss)

49,342

'

'

'

'

'

51,277

'

0

0

51,277

'

'

Repurchase of common stock (shares)

'

6,781,768

'

'

'

'

'

'

'

'

'

'

'

Repurchase of shares of common stock

-9,753

-9,753

0

0

-9,753

0

'

'

'

'

'

'

'

Reclassification of par value of common stock

0

-306,532

306,532

0

0

0

0

'

-225,431

225,431

0

'

'

Issuance of preferred stock (shares)

'

'

'

'

'

'

'

'

'

'

'

6,906

2,140,000

Issuance of preferred stock

'

'

'

'

'

'

50,181

'

0

50,160

0

'

21

Preferred stock dividends

'

'

'

'

'

'

-9,378

-847

0

0

-9,378

'

'

Issuance of restricted stock, net of forfeitures (shares)

'

1,550,817

'

'

'

'

'

'

'

'

'

'

'

Issuance of restricted stock, net of forfeitures

-334

0

-334

0

-334

0

'

'

'

'

'

'

'

Exercise of stock options, net of forfeitures (shares)

'

10,000

'

'

'

'

'

'

'

'

'

'

'

Exercise of stock options, net of forfeitures

0

0

0

0

0

0

'

'

'

'

'

'

'

Stock based compensation

3,435

0

3,435

0

3,435

0

'

'

'

'

'

'

'

Net loss

39,964

0

0

39,964

39,964

0

'

'

'

'

'

'

'

Issuance of preferred stock of subsidiary

50,181

0

0

0

0

50,181

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2013

210,029

61

337,969

-254,823

83,207

126,822

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2013

83,207

'

'

'

'

'

175,544

'

0

352,192

-176,709

40

21

Balance at end of period (in shares) at Dec. 31, 2013

'

61,211,658

'

'

'

'

'

'

750

'

'

3,958,160

2,140,000

Balance at beginning of period at Sep. 30, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income (loss)

-364

'

'

'

'

'

559

'

'

'

'

'

'

Net loss

-3,344

'

'

'

'

'

-2,421

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2013

210,029

'

'

'

'

'

'

'

'

'

'

'

'

Balance at end of period at Dec. 31, 2013

$83,207

'

'

'

'

'

$175,544

'

'

'

'

'

'

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:	'		'		'
Net income (loss)	$49,342		($153,791)		($740)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'		'		'
Depreciation, depletion and amortization	32,449		25,424		15,216
Impairment of natural gas and oil properties	0		150,787		0
Stock-based compensation	3,435		3,295		2,612
Total loss (gain) on commodity derivatives contracts	4,752		-7,422		-12,204
Cash settlements of matured commodity derivative contracts, net	-5,892		-16,251		-11,449
Cash premiums paid for commodity derivatives contracts	-152		-4,539		-3,370
Amortization of deferred financing costs	2,322	[1],[2]	224	[1],[2]	249	[1],[2]
Accretion of asset retirement obligation	468		388		534
Settlement of asset retirement obligation	-66		-636		0
Gain on acquisition of assets at fair value	-27,670		0		0
Deferred tax benefit	-16,042		0		0
Changes in operating assets and liabilities:	'		'		'
Accounts receivable	-8,431		2,487		-6,672
Prepaid expenses	-48		146		-100
Accounts payable and accrued liabilities	1,563		4,441		4,303
Net cash provided by operating activities	47,814		37,055		11,277
CASH FLOWS FROM INVESTING ACTIVITIES:	'		'		'
Development and purchase of oil and natural gas properties	-95,343		-136,311		-73,718
Advances to operators	-22,213		-9,649		-8,392
Acquisition of oil and natural gas properties	-251,096		0		0
Proceeds from sale of oil and natural gas properties	112,201		0		0
(Use of proceeds) proceeds from non-operators	-8,281		-1,983		18,740
Purchase of furniture and equipment	-766		-296		-454
Net cash used in investing activities	-265,498		-148,239		-63,824
CASH FLOWS FROM FINANCING ACTIVITIES:	'		'		'
Repurchase of common stock	-9,753		0		0
Proceeds from revolving credit facility	19,000		98,000		71,000
Repayment of revolving credit facility	-117,000		-30,000		-41,000
Proceeds from issuance of senior secured notes, net of discount	312,279		0		0
Proceeds from issuance of preferred stock, net of issuance costs	50,183		49,250		27,391
Dividends on preferred stock attributable to non-controlling interest	-9,378		-7,077		-1,024
Deferred financing charges	-3,785		-450		-276
Other	-370		-285		-336
Net cash provided by financing activities	241,176		109,438		55,755
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	23,492		-1,746		3,208
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	8,901		10,647		7,439
CASH AND CASH EQUIVALENTS, END OF PERIOD	32,393		8,901		10,647
Gastar Exploration USA Inc.	'		'		'
CASH FLOWS FROM OPERATING ACTIVITIES:	'		'		'
Net income (loss)	51,277		-152,322		285
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'		'		'
Depreciation, depletion and amortization	32,449		25,424		15,216
Impairment of natural gas and oil properties	0		150,787		0
Stock-based compensation	3,435		3,295		2,612
Total loss (gain) on commodity derivatives contracts	4,752		-7,422		-12,204
Cash settlements of matured commodity derivative contracts, net	-5,892		-16,251		-11,449
Cash premiums paid for commodity derivatives contracts	-152		-4,539		-3,370
Amortization of deferred financing costs	2,322		224		249
Accretion of asset retirement obligation	468		388		534
Settlement of asset retirement obligation	-66		-636		0
Gain on acquisition of assets at fair value	-27,670		0		0
Deferred tax benefit	-16,042		0		0
Changes in operating assets and liabilities:	'		'		'
Accounts receivable	-8,426		2,485		-6,669
Prepaid expenses	-27		169		-137
Accounts payable and accrued liabilities	1,571		4,508		4,236
Net cash provided by operating activities	49,783		38,612		12,201
CASH FLOWS FROM INVESTING ACTIVITIES:	'		'		'
Development and purchase of oil and natural gas properties	-95,343		-136,311		-73,718
Advances to operators	-22,213		-9,649		-8,392
Acquisition of oil and natural gas properties	-251,096		0		0
Proceeds from sale of oil and natural gas properties	112,201		0		0
(Use of proceeds) proceeds from non-operators	-8,281		-1,983		18,740
Purchase of furniture and equipment	-766		-296		-454
Net cash used in investing activities	-265,498		-148,239		-63,824
CASH FLOWS FROM FINANCING ACTIVITIES:	'		'		'
Proceeds from revolving credit facility	19,000		98,000		71,000
Repayment of revolving credit facility	-117,000		-30,000		-41,000
Proceeds from issuance of senior secured notes, net of discount	312,279		0		0
Proceeds from issuance of preferred stock, net of issuance costs	50,183		49,250		27,391
Dividends on preferred stock attributable to non-controlling interest	-9,378		-7,077		-1,024
Deferred financing charges	-3,785		-450		-276
Distribution to Parent, net	-12,061		-1,824		-1,374
Other	-36		25		100
Net cash provided by financing activities	239,202		107,924		54,817
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	23,487		-1,703		3,194
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	8,892		10,595		7,401
CASH AND CASH EQUIVALENTS, END OF PERIOD	$32,379		$8,892		$10,595
[1]	The year ended DecemberB 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. See Note 4, bLong-Term Debt - Second Amended and Restated Revolving Credit Facility.b
[2]	The year ended DecemberB 31, 2013 includes $716,000 of debt discount accretion related to the Notes.

Description_Of_Business

Description Of Business	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Description of business	'
	Description of Business
	Gastar Exploration, Inc., formerly known as Gastar Exploration Ltd., is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the United States (“U.S.”). Gastar Exploration, Inc.’s principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. Gastar Exploration, Inc. is currently pursuing development within the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play in Oklahoma and the development of liquids-rich natural gas in the Marcellus Shale and Utica Shale plays in West Virginia. Gastar Exploration, Inc. also holds prospective Marcellus Shale acreage in Pennsylvania. Gastar Exploration, Inc. sold substantially all of its East Texas assets on October 2, 2013, with an effective date of January 1, 2013.
	On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation, changed its jurisdiction of incorporation to the State of Delaware and changed its name to “Gastar Exploration, Inc.” At December 31, 2013, Gastar Exploration, Inc. was a holding company and substantially all of its operations were conducted through, and substantially all of its assets were held by, its primary operating subsidiary, Gastar Exploration USA, Inc. and its wholly-owned subsidiaries. Subsequently, on January 31, 2014, Gastar Exploration, Inc. merged with and into Gastar Exploration USA, Inc. as part of a reorganization to eliminate the holding company corporate structure. Pursuant to the merger agreement, shares of the Gastar Exploration Inc.'s common stock were converted into an equal number of shares of common stock of Gastar USA and Gastar USA changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc., together with its subsidiaries, owns and will continue to conduct business in substantially the same manner as was being conducted by Gastar Exploration, Inc. and its subsidiaries prior to the merger. Unless otherwise stated or the context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) and its wholly-owned subsidiaries, all references to “Parent” refer solely to Gastar Exploration, Inc. (formerly known as Gastar Exploration Ltd.), and all references to “Gastar,” the “Company” and similar terms refer collectively to Gastar Exploration, Inc. and its wholly-owned subsidiaries, including Gastar Exploration USA, Inc.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Basis of Presentation
	These financial statements are a combined presentation of the consolidated financial statements of the Company and Gastar USA, as predecessors to Gastar Exploration Inc., in satisfaction of Rule 12g-3(g) of the Securities Exchange Act of 1934. Separate information is provided for the Company and Gastar USA as required. Except as otherwise noted, there are no material differences between the consolidated information for the Company presented herein and the consolidated information of Gastar USA.
	The consolidated financial statements of the Company and Gastar USA are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved natural gas and oil reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows. See Note 18, “Supplemental Oil and Gas Disclosures.”
	Reclassifications
	Certain reclassifications of prior year balances have been made to conform to current year presentation; these reclassifications have no impact on net income (loss).
	Subsequent Events
	In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate.
	Principles of Consolidation
	The consolidated financial statements of the Company include the accounts of Parent and the consolidated accounts of all its subsidiaries. The wholly-owned subsidiaries included in these consolidated accounts are Gastar USA, Gastar Exploration Texas, Inc. (“Gastar Texas, Inc.”), Gastar Exploration Texas LP (“Gastar Texas”), Gastar Exploration Texas LLC (“Gastar Texas LLC”), Gastar Exploration New South Wales, Inc. (“Gastar New South Wales”), and prior to 2012, Gastar Exploration Victoria, Inc. (“Gastar Victoria”). All significant inter-company accounts and transactions have been eliminated in consolidation.
	The consolidated financial statements of Gastar USA include the accounts of Gastar USA and the consolidated accounts of all its subsidiaries. The wholly-owned subsidiaries included in these consolidated accounts are Gastar Texas, Inc., Gastar Texas, Gastar Texas LLC, Gastar New South Wales, and prior to 2012, Gastar Victoria. All significant inter-company accounts and transactions have been eliminated in consolidation.
	Use of estimates in Preparation of Financial Statements
	The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate , natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties.
	Cash and Cash Equivalents
	The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $32.4 million and $8.9 million as of December 31, 2013 and 2012, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.
	Accounts Receivable
	Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible.
	A summary of the activity related to the allowance for doubtful accounts is as follows:
		For the years ended December 31,
		2013			2012			2011
		(in thousands)
	Allowance for doubtful accounts, beginning of year	$	546		$	551		$	571
	Expense	—			—			—
	Reductions/write-offs	(39		)	(5		)	(20		)
	Allowance for doubtful accounts, end of year	$	507		$	546		$	551
	Oil and Natural Gas Properties
	The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center.
	Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.
	Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations.
	In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.
	The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2013 and 2012 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. The previous rules required that reserve estimates be calculated using year-end pricing.
	Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered.
	The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted.
	Asset Retirement Obligation
	Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations.
	Furniture and Equipment
	Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years.
	Capitalized Interest
	The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The primary debt instrument included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2013 was the Notes. Currently, the Company only capitalizes interest on the Notes. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $3.3 million, $1.9 million and $818,000 for 2013, 2012 and 2011, respectively.
	Fair Value of Financial Instruments
	The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value.
	Deferred Financing Costs
	Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense.
	The following table indicates deferred charges and related accumulated amortization as of the dates indicated:
		As of December 31,
		2013			2012
	Deferred charges	$	3,269		$	2,525
	Accumulated amortization	(319		)	(1,689		)
	Deferred charges, net	$	2,950		$	836
	Derivative Instruments and Hedging Activity
	The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.”
	The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in (loss) gain on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in (loss) gain on commodity derivatives contracts in the Company’s consolidated statement of operations.
	Stock-Based Compensation
	The Company reports compensation expense for restricted common stock, performance based units (“PBUs”) and stock options granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.
	Stock-based compensation cost for restricted shares is estimated at the grant date based on the award's fair value, which is equal to the prior day's closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant based on the award's fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. The Company did not award any stock option grants during 2013, 2012 or 2011.
	Treasury Stock
	Treasury stock purchases are recorded at cost as a reduction to common stock. Shares of common stock are canceled upon repurchase.
	Revenue Recognition
	The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company's NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company's wet gas production. The Company's reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which the Company is credited under its sales contracts. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2013 and 2012.
	The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, oil, condensate, natural gas and NGLs volumes sold are not significantly different from the Company’s share of production.
	The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet.
	Deferred Income Taxes
	Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. 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. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.
Comprehensive Income
Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Company has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.
Earnings or Loss per Share
Basic earnings or loss per share is computed on the basis of the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed based upon the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of stock options, unvested restricted shares and PBUs.
Joint Venture Operations
The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, development and production of natural gas and oil. Historically, the Company’s operational activities have been conducted in the U.S. and Australia, with only the U.S. having revenue generating operating results. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.
Foreign Currency Exchange
The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the Company is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction.
All of the Company’s operations are conducted in U.S. dollars. Prior to July 2009, the Company conducted natural gas property development in Australia; however, prior to reaching commercial operations, these assets were sold. The Company owns non-operating working interests in two gas wells located in Alberta, Canada, from which it has received no revenue since January 1, 2012.
The Australian and Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations.
Recent Accounting Developments
The following recently issued accounting pronouncements have been adopted or may impact us in future periods:
Income taxes. In July 2013, the FASB issued an amendment to previously issued guidance regarding the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The amendment requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except as follows. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and should be made presuming disallowance of the tax position at the reporting date. This amendment does not require new recurring disclosures. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Earlier application is permitted. The adoption of this guidance is not expected to impact our operating results, financial position or cash flows upon adoption.

Property_Plant_And_Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant And Equipment	'
	Property, Plant and Equipment
	The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of West Virginia, Pennsylvania, Oklahoma, Texas, Wyoming and Montana. The Company sold substantially all of its interest in East Texas on October 2, 2013, with an effective date of January 1, 2013. The Company's working interest in its Wyoming and Montana properties in the Powder River Basin were assigned to the operator on May 3, 2012, with an effective date of January 1, 2012. The Company's total property, plant and equipment consists of the following:
		December 31,
		2013				2012
		(in thousands)
	Oil and natural gas properties, full cost method of accounting:
	Unproved properties	$	96,220			$	67,892
	Proved properties	935,773				671,193
	Total oil and natural gas properties	1,031,993				739,085
	Furniture and equipment	2,691				1,925
	Total property and equipment	1,034,684				741,010
	Impairment of proved natural gas and oil properties	(337,939		)		(337,939		)
	Accumulated depreciation, depletion and amortization	(179,232		)		(146,820		)
	Total accumulated depreciation, depletion and amortization	(517,171		)		(484,759		)
	Total property and equipment, net	$	517,513			$	256,251
	Included in the Company's oil and natural gas properties are asset retirement costs of $3.4 million and $4.8 million as of December 31, 2013 and 2012, respectively.
	The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:
		December 31,
		2013				2012
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	4,774			$	1,902
	Acreage acquisition costs	86,097				62,395
	Capitalized interest	5,349				3,595
	Total unproved properties excluded from amortization	$	96,220			$	67,892
	For the year ended December 31, 2013, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $20.5 million of unproved properties to proved properties for the year ended December 31, 2013. For the year ended December 31, 2012, management's evaluation of unproved properties resulted in an impairment. Due to a decline in natural gas prices and the suspension of drilling activity in East Texas, the Company reclassified $24.4 million of unproved properties to proved properties for the year ended December 31, 2012.
	The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of natural gas and oil properties is not reversible at a later date even if natural gas and oil prices increase. The ceiling calculation dictates that the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely. The 12-month unweighted arithmetic average of the first-day-of-the-month prices are adjusted for basis and quality differentials in determining the present value of the reserves. The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted:
			2013
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu) (1)						$	3.67		$	3.61	$	3.44	$	2.95
	West Texas Intermediate oil price (per Bbl) (1)						$	96.78		$	91.69	$	88.13	$	89.17
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
			2012
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu) (1)						$	2.76		$	2.83	$	3.15	$	3.73
	West Texas Intermediate oil price (per Bbl) (1)						$	91.21		$	91.48	$	92.17	$	94.65
	Impairment recorded (pre-tax) (in thousands)		$	150,787			$	—		$	78,054	$	72,733	$	—
			2011
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu) (1)						$	4.12		$	4.16	$	4.21	$	4.1
	West Texas Intermediate oil price (per Bbl) (1)						$	92.71		$	91	$	86.6	$	80.04
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
	_________________________________
	-1	For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.
	Future declines in the 12-month average of oil, condensate, natural gas and NGLs prices could result in the recognition of future ceiling impairments.
	Chesapeake Acquisition
	On March 28, 2013, Gastar USA entered into a Purchase and Sale Agreement by and among Chesapeake Exploration, L.L.C., Arcadia Resources, L.P., Jamestown Resources, L.L.C., Larchmont Resources, L.L.C. (together, the “Chesapeake Parties”) and Gastar USA (the “Chesapeake Purchase Agreement”). Pursuant to the Chesapeake Purchase Agreement, Gastar USA was to acquire approximately 157,000 net acres of Oklahoma oil and gas leasehold interests from the Chesapeake Parties, including production from interests in 206 producing wells located in Oklahoma (the “Chesapeake Assets”). The Chesapeake Purchase Agreement contained customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in the Chesapeake Purchase Agreement. On June 7, 2013, the parties to the Chesapeake Purchase Agreement entered into an Amendment to Purchase and Sale Agreement, dated June 7, 2013, in order to revise the description of the properties to be acquired and to evidence the withdrawal of Arcadia Resources, L.P. and Jamestown Resources, L.L.C. from the Chesapeake Purchase Agreement. Pursuant to the Chesapeake Purchase Agreement, as amended, on June 7, 2013, Gastar USA completed the acquisition of the Chesapeake Assets for a final adjusted purchase price of $69.4 million, reflecting adjustment for an acquisition effective date of October 1, 2012.
	Upon completion of the initial purchase price allocation, as of June 7, 2013, the Company reviewed and verified its assessment, including the identification and valuation of assets acquired. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $2.1 million of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the Chesapeake Assets resulted in a fair market valuation of $113.1 million. With the completion of the asset valuation during the fourth quarter of 2013, the Company recorded the deferred tax attributes associated with the transaction. As a result of incorporating the final valuation information into the purchase price allocation, a bargain purchase gain of $27.7 million was recognized in the accompanying consolidated statements of operations. The bargain purchase gain was primarily attributable to the non-strategic nature of the divestiture to the seller, coupled with favorable economic trends in the industry and the geographic region in which the Chesapeake Assets are located. The Company believes the estimates used in the fair market valuation and purchase price allocation are reasonable and that the significant effects of the acquisition are properly reflected.
	The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Chesapeake Acquisition (in thousands):
	Consideration:
	Cash consideration		$	69,371
	Fair Value of Liabilities Assumed:
	Deferred tax liability		16,042
	Total purchase price plus liabilities assumed		$	85,413
	Estimated Fair Value of Assets Acquired:
	Unproved properties		$	86,327
	Proved properties		26,756
	Total assets acquired		$	113,083
	Bargain purchase gain		$	27,670
	Hunton Joint Venture AMI Election
	Effective July 1, 2013, Gastar USA's working interest partner in its original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties that Gastar USA acquired pursuant to the Chesapeake Purchase Agreement for a total payment of $11.8 million, of which $133,000 was deemed to be a reimbursement of transaction and integration costs associated with the acquisition and was recorded as a reduction of general and administrative expense.
	Hunton Divestiture
	On July 2, 2013, Gastar USA entered into a purchase and sale agreement with Newfield Exploration Mid-Continent Inc. (“Newfield”), dated July 2, 2013, pursuant to which Newfield acquired approximately 76,000 net undeveloped acres of oil and gas leasehold interests in Kingfisher and Canadian Counties, Oklahoma from Gastar USA and Gastar USA acquired approximately 1,850 net acres of Oklahoma oil and gas leasehold interests from Newfield. The transaction closed on August 6, 2013 for a net cash purchase price of approximately $57.0 million, adjusted for an acquisition effective date of May 1, 2013. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.
WEHLU Acquisition
On September 4, 2013, Gastar USA entered into a Purchase and Sale Agreement, dated September 4, 2013, by and among Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (the “Lime Rock Parties”) and Gastar USA (the “WEHLU Purchase Agreement”). Pursuant to the WEHLU Purchase Agreement, Gastar USA acquired a 98.3% working interest (80.5% net revenue interest) in 24,000 net acres of the West Edmond Hunton Lime Unit (“WEHLU”) located in Kingfisher, Logan and Oklahoma Counties, Oklahoma, all of which is held by production (“WEHLU Assets”). Pursuant to the WEHLU Purchase Agremeent, Gastar USA completed the acquisition of the WEHLU Assets on November 15, 2013 for an adjusted cash purchase price of $177.8 million, reflecting customary adjustments and adjustment for an acquisition effective date of August 1, 2013 (the “WEHLU Acquisition”).
The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $286,000 of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the WEHLU Assets resulted in a fair market valuation of $176.8 million. As the fair market valuation varied less than 1% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation.
The following table summarizes the estimated fair value of the assets acquired in connection with the WEHLU Acquisition (in thousands):
Consideration:
Cash consideration		$	177,778
Estimated Fair Value of Assets Acquired:
Unproved properties		$	13,026
Proved properties		164,752
Total assets acquired		$	177,778
Chesapeake and WEHLU Acquisition Pro Forma Operating Results
The following unaudited pro forma results for the years ended December 31, 2013 and 2012 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of each respective period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.
		For the Years Ended December 31,
		2013				2012
		(in thousands, except per share data)
		(Unaudited)
Revenues		$	132,721			$	97,760
Net Loss		$	(4,836	)		$	(175,809	)
Loss per share:
Basic		$	(0.08	)		$	(2.77	)
Diluted		$	(0.08	)		$	(2.77	)
The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Chesapeake and WEHLU Acquisitions occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information.
The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Chesapeake and WEHLU Acquisitions are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes.
		Year Ended December 31, 2013
		(in thousands)
Revenues		$	11,292
Excess of revenues over direct operating expenses		$	7,591
Hilltop Area, East Texas Sale
On April 19, 2013, Gastar Exploration Texas, LP (“Gastar Texas”) and Gastar USA entered into a Purchase and Sale Agreement by and among Gastar Texas, Gastar USA and Cubic Energy, Inc. (“Cubic Energy”) (the “East Texas Sale Agreement”). Pursuant to the East Texas Sale Agreement, as amended, on October 2, 2013, Cubic Energy acquired from Gastar Texas approximately 31,800 gross (16,300 net) acres of leasehold interests in the Hilltop area of East Texas in Leon and Robertson Counties, Texas, including production from interests in producing wells, for net proceeds of approximately $42.9 million, reflecting adjustment for accounting effective date of January 1, 2013 and other customary adjustments. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.
Atinum Joint Venture
In September 2010, Gastar USA entered into a joint venture (the “Atinum Joint Venture”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum”), a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on November 1, 2010, Gastar USA assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania, which consisted of approximately 37,600 gross (34,200 net) acres and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well (the “Atinum Joint Venture Assets”). Atinum paid Gastar USA approximately $30.0 million in cash at the closing and paid an additional $40.0 million of Gastar USA's share of drilling costs over time in the form of a “drilling carry.” Upon completion of the funding of the drilling carry, Gastar USA made additional assignments to Atinum in early 2012 as a result of which Atinum owns a 50% interest in the Atinum Joint Venture Assets. The terms of the drilling carry required Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of Gastar USA’s ultimate 50% share of those same costs until the $40.0 million drilling carry had been satisfied. As of December 31, 2011, Atinum had completed the funding of the $40.0 million drilling carry. Subsequent to December 31, 2011, Atinum funds only its 50% share of costs.
The Atinum Joint Venture pursued an initial three-year development program that called for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 operated horizontal wells in each of 2012 and 2013, respectively. Due to natural gas price declines, Atinum and Gastar USA agreed to reduce the 2012 minimum wells to be drilled requirement from 24 wells to 20 wells and then subsequently agreed to extend the rig contract resulting in 29 gross (13.4 net) wells drilled and completed during 2012. As of December 31, 2012, 38 gross (17.4 net) operated wells were drilled, completed and on production under the Atinum Joint Venture. Due to continued natural gas price declines, Atinum and Gastar USA agreed to reduce the 2013 minimum wells to be drilled requirement to 19 wells which would result in 57 gross wells on production at December 31, 2013, compared to the 60 gross wells originally agreed upon. As of December 31, 2013, all 57 gross (27.0 net) wells were on production as agreed upon.
Subsequent to June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, Gastar USA acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay Gastar USA on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	Second Amended and Restated Revolving Credit Facility
	On June 7, 2013, Gastar USA entered into the Second Amended and Restated Credit Agreement, dated as of June 7, 2013, among Gastar USA, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). The New Revolving Credit Facility provides an initial borrowing base of $50.0 million, with borrowings bearing interest, at Gastar USA's election, at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent or (ii) the federal funds rate plus 50 basis points. The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The New Revolving Credit Facility has a scheduled maturity of November 14, 2017.
	The Revolving Credit Facility is guaranteed by all of Gastar USA's current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA and its subsidiaries, excluding de minimus value properties as determined by the lender. The Revolving Credit Facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of any foreign subsidiary of Gastar USA.
	The Revolving Credit Facility contains various covenants, including among others:
	•	Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments;
	•	Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted;
	•	Maintenance of a maximum ratio of indebtedness to EBITDA of not greater than 4.0 to 1.0; and
	•	Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0.
	All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including among others:
	•	Failure to make payments;
	•	Non-performance of covenants and obligations continuing beyond any applicable grace period; and
	•	The occurrence of a change in control of Gastar USA, as defined in the Revolving Credit Facility.
	On July 31, 2013, Gastar USA, together with the parties thereto, entered into the Waiver, Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement (the “First Amendment”). The First Amendment amended the Revolving Credit Facility to clarify the current ratio covenant calculation.
	On October 18, 2013, Gastar USA, together with the parties thereto, entered into the Agreement and Amendment No. 2 (“Amendment No. 2”) to Second Amended and Restated Credit Agreement, dated as of June 7, 2013. Amendment No. 2 amended the Revolving Credit Facility to, among other things, (i) increase the aggregate principal amount of the Notes permitted to be issued from $200.0 million to $325.0 million, (ii) allow for the issuance by Gastar USA of Series B Preferred Stock and (iii) increase the aggregate amount of cash dividends permitted to be paid to preferred stockholders from $12.5 million to $20.0 million.
	On December 9, 2013, the borrowing base under the Revolving Credit Facility was increased by the lending participants to $100.0 million.
	Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. Gastar USA and its lenders may each request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. At December 31, 2013, the Revolving Credit Facility had a borrowing base of $100.0 million, with no borrowings outstanding and availability of $100.0 million. The next regularly scheduled redetermination is set for May 2014. Future increases in the borrowing base in excess of the original $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets as defined in the Notes agreement (as discussed below in “Senior Secured Notes”).
	On December 18, 2013, Parent entered into a parent guarantee agreement (the “Credit Facility Guaranty”) to guaranty Gastar USA’s obligations under the Revolving Credit Facility. Pursuant to the Credit Facility Guaranty, Parent irrevocably and unconditionally guaranteed the punctual payment and performance of all obligations under the Revolving Credit Facility, subject to fraudulent transfer laws, in the manner and to the extent set forth in the Credit Facility Guaranty.
	At December 31, 2013, Gastar USA was in compliance with all financial covenants under the Revolving Credit Facility.
	Amended and Restated Revolving Credit Facility
	For the period October 28, 2009 through June 6, 2013, Gastar USA, together with the other parties thereto, was subject to an amended and restated credit facility (the “Prior Revolving Credit Facility”). The Prior Revolving Credit Facility provided for various borrowing base amounts based on an initial borrowing base of $47.5 million and a final borrowing base of $160.0 million effective March 31, 2013. Borrowings bore interest, at Gastar USA’s election, at the prime rate or LIBO rate plus an applicable margin. The applicable interest rate margin varied from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings based on LIBO rate, depending on the utilization percentage in relation to the borrowing base. An annual commitment fee of 0.5% was payable quarterly based on the unutilized balance of the borrowing base. The Prior Revolving Credit Facility had a final scheduled maturity date of September 30, 2015.
	The Prior Revolving Credit Facility was guaranteed by Parent (as defined in the Prior Revolving Credit Facility) and all of Gastar USA’s current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Prior Revolving Credit Facility. Borrowings and related guarantees were secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA and its subsidiaries, excluding de minimus value properties as determined by the lender. The facility was secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of each foreign subsidiary of Gastar USA.
	The Prior Revolving Credit Facility contained various covenants, including among others:
	•	Restrictions on liens, incurrence of other indebtedness without lenders' consent and other restricted payments including a restriction on the amount of cash dividends to be paid in aggregate on the Gastar USA Series A Preferred Stock each calendar year, subject to certain available commitment thresholds;
	•	Limitation of hedging volumes with a final limitation of 100% of the proved developed reserves as reflected in Gastar USA's reserve report using hedging other than floors and protective spreads;
	•	Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted, except for quarters ending on March 31, 2013 through December 31, 2013 whereby the ratio was reduced to 0.6 to 1.0 and making certain changes in the calculation of current liabilities for such periods to exclude advances from non-operators;
	•	Maintenance of a maximum ratio of indebtedness to EBITDA on a rolling four quarter basis, as adjusted, of not greater than 4.0 to 1.0; and
	•	Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0.
	All outstanding amounts owed became due and payable upon the occurrence of certain usual and customary events of default, including among others:
	•	Failure to make payments;
	•	Non-performance of covenants and obligations continuing beyond any applicable grace period; and
	•	The occurrence of a “Change in Control” (as defined in the Prior Revolving Credit Facility) of the Parent.
	The Prior Revolving Credit Facility was amended and restated on June 7, 2013.
	Senior Secured Notes
	On May 15, 2013, Gastar USA issued $200.0 million aggregate principal amount of its 8 5/8% Senior Secured Notes due May 15, 2018 under an indenture (the “Indenture”) by and among Gastar USA, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). On November 15, 2013, Gastar USA issued an additional $125.0 million aggregate principal amount of additional notes under the Indenture. The 8 5/8% Senior Secured Note due 2018 are collectively referred to as the “Notes.” The Notes bear interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. The Notes will mature on May 15, 2018. The Company received net proceeds of approximately $312.3 million, net of debt issuance costs and any original issue discounts.
	In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require Gastar USA to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase.
	The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of Gastar USA's material subsidiaries and certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of Gastar USA's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of Gastar USA's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to Gastar USA's unsecured indebtedness and effectively subordinated to Gastar USA's and Guarantors' indebtedness under the Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation.
	The Indenture contains covenants that, among other things, limit Gastar USA's ability and the ability of its subsidiaries to:
	•	Transfer or sell assets or use asset sale proceeds;
	•	Pay dividends or make distributions, redeem subordinated debt or make other restricted payments;
	•	Make certain investments; incur or guarantee additional debt or issue preferred equity securities;
	•	Create or incur certain liens on Gastar USA's assets;
	•	Incur dividend or other payment restrictions affecting future restricted subsidiaries;
	•	Merge, consolidated or transfer all or substantially all of Gastar USA's assets;
	•	Enter into certain transactions with affiliates; and
	•	Enter into certain sale and leaseback transactions.
	These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture.
	On May 15, 2013 and November 15, 2013, in connection with each issuance and sale of the Notes, Gastar USA and each of the Guarantors entered into Registration Rights Agreements (together, the “Registration Rights Agreements”) with Imperial Capital, LLC, as representative of the initial purchasers. Under the Registration Rights Agreement, Gastar USA agreed, subject to certain exceptions, to (i) file a registration statement with the SEC with respect to an exchange of the Notes for new notes having terms substantially identical in all material respects to the Notes (except that the exchange notes will not contain terms relating to transfer restrictions), (ii) use its reasonable best efforts to cause the exchange offer registration statement to be declared effective under the Securities Act of 1933, as amended, within 360 days after the issue date of the Notes, (iii) as soon as practicable after the effectiveness of the exchange offer registration statement, offer the exchange notes in exchange for the Notes, and (iv) keep the registered exchange offer open for not less than 30 days (or longer if required by applicable law) after the date of the registered exchange offer is mailed to the holders of the Notes. Gastar USA and the Guarantors also agreed to file a shelf registration statement for the resale of the Notes if an exchange offer cannot be effected within the time period specified above and in other circumstances.
	On December 23, 2013, Parent entered into the Parent Guarantee Agreement (the “Notes Guarantee”). Pursuant to the Notes Guarantee, Parent jointly and severally, unconditionally guaranteed all notes issued under the indenture governing the Notes.
	At December 31, 2013, the Notes reflected a balance of $313.0 million, net of unamortized discounts of $12.0 million, on the consolidated balance sheets.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligation	'
	Asset Retirement Obligation
	A summary of the activity related to the asset retirement obligation is as follows:
		For the years ended December 31,
		2013			2012			2011
		(in thousands)
	Asset retirement obligation, beginning of year	$	6,963		$	8,275		$	7,249
	Liabilities incurred during period	3,416			271			492
	Liabilities settled during period	(126		)	(297		)	—
	Accretion expense	468			388			534
	Revision in previous estimates and other	60			553			—
	Deletions related to property disposals	(4,718		)	$	(2,227	)	—
	Asset retirement obligation, end of year	$	6,063		$	6,963		$	8,275
	As of December 31, 2013, the current portion of the Company's asset retirement obligation was $633,000 and was recorded in current liabilities on the consolidated balance sheet.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties, which are Level 3 inputs. For the years ended December 31, 2013 and 2012, management's evaluation of unproved properties resulted in an impairment. Due to continued low natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East or East Texas, the Company reclassified $20.5 million and $24.4 million of unproved properties to proved properties for the years ended December 31, 2013 and 2012, respectively. As no other fair value measurements are required to be recognized on a non-recurring basis at December 31, 2013, no additional disclosures are provided at December 31, 2013.
	As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:
	•	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds.
	•	Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.
	•	Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.
	As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets.
	Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2013 and 2012 periods.
	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012:
		Fair value as of December 31, 2013
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	32,393		$	—		$	—		$	32,393
	Commodity derivative contracts	—			—			7,545			7,545
	Liabilities:
	Commodity derivative contracts	—			—			(3,781		)	(3,781		)
	Total	$	32,393		$	—		$	3,764		$	36,157
		Fair value as of December 31, 2012
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	8,901		$	—		$	—		$	8,901
	Restricted cash	—			—			—			—
	Commodity derivative contracts	—			—			9,168			9,168
	Liabilities:
	Commodity derivative contracts	—			—			(2,703		)	(2,703		)
	Total	$	8,901		$	—		$	6,465		$	15,366
	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2013 and 2012. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2013 and 2012.
		For the years ended December 31,
		2013			2012
		(in thousands)
	Balance at beginning of period	$	6,465		$	15,873
	Total gains (losses):
	included in earnings	(4,752		)	7,236
	Purchases	9,772			—
	Issuances	(2,308		)	—
	Settlements (1)	(5,413		)	(16,644		)
	Balance at end of period	$	3,764		$	6,465
	The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2013 and 2012	$	(9,967	)	$	(5,566	)
	_________________________________
	-1	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations.
	At December 31, 2013, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at December 31, 2013 was $324.6 million based on quoted market prices of the senior secured notes (Level 1). The estimated fair value of the Company’s long-term debt at December 31, 2012 approximated the respective carrying value because the interest rate approximated the current market rate (Level 2).
	The Company has consistently applied the valuation techniques discussed above in all periods presented.
	The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivative Instruments and Hedging Activity.”

Derivative_Instruments_And_Hed

Derivative Instruments And Hedging Activity	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments And Hedging Activity	'
	Derivative Instruments and Hedging Activity
	The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk.
	All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in (loss) gain on commodity derivatives contracts. For the year ended December 31, 2013, the Company reported a loss of $4.8 million in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. For the years ended December 31, 2012 and 2011, the Company reported gains of $7.4 million and $12.2 million, respectively, in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments.
	As of December 31, 2013, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume			Volume			Price
					(in MMBtu's)
	2014		Fixed price swap		11,136			4,064,500			$	4.06			$	—	$	—	$	—
	2014		Fixed price swap		2,000			730,000			3.72				—		—		—
	2014		Fixed price swap		2,000			730,000			3.98				—		—		—
	2014		Fixed price swap		2,000			730,000			4.07				—		—		—
	2014		Short calls		2,500			912,500			—				—		—		4.59
	2014		Costless collar		3,000			1,095,000			—				4		—		4.36
	2014		Costless collar		5,000			1,825,000			—				4		—		4.55
	2014		Costless collar		2,500			912,500			—				4		—		4.71
	2014 (1)		Short puts		10,500			966,000			—				—		3		—
	2015		Fixed price swap		400			146,000			4				—		—		—
	2015		Fixed price swap		2,500			912,500			4.06				—		—		—
	2015		Protective spread		2,600			949,000			4				—		3.25		—
	2015		Costless three-way collar		2,000			760,000			—				4		3.25		4.58
	2016		Protective spread		2,000			732,000			4.11				—		3.25		—
	2016		Costless three-way collar		2,000			732,000			—				4		3.25		4.58
	_______________________________
	-1	For the period October to December 2014.
	As of December 31, 2013, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume (1)			Volume			Price
					(in Bbls)
	2014 (2)		Fixed price swap		300			54,300			$	98.05			$	—	$	—	$	—
	2014 (2)		Fixed price swap		550			99,550			95.15				—		—		—
	2014 (2)		Fixed price swap		900			162,900			93.21						—		—
	2014 (3)		Fixed price swap		750			138,000			90.35				—		—		—
	2014 (3)		Fixed price swap		200			36,800			93				—		—		—
	2014 (3)		Fixed price swap		350			64,400			91.55				—		—		—
	2014		Fixed price swap		500			182,500			91.1				—		—		—
	2014		Fixed price swap		270			98,500			90.77				—		—		—
	2014		Costless collar		200			73,000			—				98		—		98
	2014 (4)		Put spread		200			24,400			—				93		73		—
	2015		Costless three-way collar		400			146,000			—				85		70		96.5
	2015		Costless three-way collar		345			126,100			—				85		65		97.8
	2015 (5)		Costless three-way collar		150			27,150			—				85		65		96.25
	2015 (6)		Costless three-way collar		50			9,200			—				85		65		96.25
	2015 (5)		Put spread		700			126,700			—				90		70		—
	2015		Put spread		250			91,250			—				89		69		—
	2015 (6)		Put spread		600			110,400			—				87		67		—
	2016		Costless three-way collar		275			100,600			—				85		65		95.1
	2016		Costless three-way collar		330			120,780			—				80		65		97.35
	2016		Put spread		550			201,300			—				85		65		—
	2016		Put spread		300			109,800			—				85.5		65.5		—
	2017		Costless three-way collar		280			102,200			—				80		65		97.25
	2017		Costless three-way collar		242			88,150			—				80		60		98.7
	2017		Put spread		500			182,500			—				82		62		—
	2018 (7)		Put spread		425			103,275			—				80		60		—
	_______________________________
	-1	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
	-2	For the period January to June 2014.
	-3	For the period July to December 2014.
	-4	For the period September to December 2014.
	-5	For the period January to June 2015.
	-6	For the period July to December 2015.
	-7	For the period January to August 2018.
As of December 31, 2013, the Company did not have any NGLs derivative transactions outstanding.
As of December 31, 2013, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.
In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period December 2013 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company began amortizing the deferred put premium liabilities in December 2013. The following table provides information regarding the deferred put premium liabilities for the periods indicated:
	For the Years Ended December 31,
	2013				2012
	(in thousands)
Current commodity derivative premium put payable	$	145			$	—
Long-term commodity derivative premium payable	7,000				—
Total unamortized put premium liabilities	$	7,145			$	—
The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2013:
	Amortization
	(in thousands)
September to December 2014	$	145
January to December 2015	2,298
January to December 2016	2,408
January to December 2017	1,460
January to August 2018	834
Total unamortized put premium liabilities	$	7,145
Additional Disclosures about Derivative Instruments and Hedging Activities
The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments:
	Fair Values of Derivative Instruments
	Derivative Assets (Liabilities)
			Fair Value
			December 31,
	Balance Sheet Location		2013				2012
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets		$	—			$	7,799
Commodity derivative contracts	Other assets		7,545				1,369
Commodity derivative contracts	Current liabilities		(3,403		)		(1,399		)
Commodity derivative contracts	Long-term liabilities		(378		)		(1,304		)
Total derivatives not designated as hedging instruments			$	3,764			$	6,465
	Amount of Gain (Loss) Recognized in Income on Derivatives
			Amount of Gain (Loss)
			Recognized in Income on
			Derivatives For the Years Ended December 31,
	Location of Gain (Loss) Recognized in		2013				2012				2011
	Income on Derivatives
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	(Loss) gain on commodity derivatives contracts		$	(4,752	)		$	7,422			$	12,204
Commodity derivative contracts	Interest expense		—				(186		)		(136		)
Total			$	(4,752	)		$	7,236			$	12,068

Capital_Stock

Capital Stock	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Capital Stock	'
	Capital Stock
	Common Stock
	On November 14, 2013, Parent changed its jurisdiction of incorporation to the State of Delaware and entered into new articles of incorporation pursuant to which 275,000,000 shares of Parent's common stock, $0.001 par value per share, are authorized for issuance. Prior to November 14, 2013, Parent’s articles of incorporation allowed Parent to issue an unlimited number of common shares without par value.
	On January 31, 2014, Parent entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Parent merged with and into Gastar USA, a direct subsidiary of Parent, as part of a reorganization to eliminate Parent's holding company corporate structure. Pursuant to the Merger Agreement, shares of Parent's common stock were converted into the right to receive an equal number of shares of common stock of Gastar USA, which together with its subsidiaries, owns and continues to conduct business in substantially the same manner as it was being conducted by Parent and its subsidiaries immediately prior to the merger.
	Parent Preferred Shares
	Under Parent's Delaware articles of incorporation, 40,000,000 shares of preferred stock, $0.01 par value per share, are authorized for issuance. At December 31, 2013, Parent had no preferred shares issued or outstanding.
	Other Share Issuances
	The following table provides information regarding the issuances and forfeitures of Parent’s common stock pursuant to Parent’s 2006 Long-Term Stock Incentive Plan for the periods indicated:
		For the Years Ended December 31,
		2013		2012
	Other stock issuances:
	Shares of restricted common stock granted	2,288,179		1,916,981
	Shares of restricted common stock vested	762,682		505,203
	Stock options exercised	10,000		3,000
	Shares of restricted common stock surrendered upon vesting/exercise (1)	224,500		141,458
	Shares of restricted common stock forfeited	512,862		74,463
	__________________
	-1	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period.
	On June 7, 2012, Parent's stockholders voted to approve the Second Amendment to Parent's 2006 Long-Term Stock Incentive Plan. This amendment, effective June 3, 2012, increased the total number of shares available for issuance under the plan from 6,000,000 shares to 11,000,000 shares. There were 1,544,838 shares available for issuance under the Parent's 2006 Long-Term Stock Incentive Plan at December 31, 2013.
	Shares Reserved
	At December 31, 2013, Parent had 874,100 shares of common stock reserved for the exercise of stock options and 1,420,981 shares reserved for the settlement of PBUs.
	Shares Owned by Chesapeake Energy Corporation
	On March 28, 2013, the Company entered into a Settlement Agreement, dated March 28, 2013, between Chesapeake Exploration, L.L.C. and Chesapeake Energy Corporation (collectively, “Chesapeake”) and the Company, Gastar Texas and Gastar Texas, LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding shares of common stock of Parent held by Chesapeake Energy Corporation upon the closing of the stock repurchase and settlement on June 7, 2013. See Note 14, “Commitments and Contingencies.”
	Gastar USA Common Stock
	At December 31, 2013 and 2012, all 750 shares of Gastar USA's common stock were held by Parent. On May 24, 2011, Gastar USA converted from a Michigan corporation to a Delaware corporation (the “Conversion”). Following the Conversion, Gastar USA’s Delaware certificate of incorporation allowed Gastar USA to issue 1,000 shares of common stock, without par value. In connection with the Conversion, the Parent’s 750 shares of common stock in the Michigan corporation were converted to 750 shares of common stock in the new Gastar USA Delaware corporation.
	On October 25, 2013, Gastar USA filed an Amended and Restated Certificate of Incorporation (the “A&R Certificate”) with the Secretary of State of the State of Delaware. Under the A&R Certificate, the capital stock authorized for issuance was increased from 1,000 shares of common stock, without par value, to 275,000,000 shares of common stock, par value $0.001 per share.
	Gastar USA Preferred Stock
	Prior to the Conversion, Gastar USA’s articles of incorporation did not authorize issuance of preferred stock.
	Following the Conversion, Gastar USA’s Delaware certificate of incorporation allowed Gastar USA to issue 10,000,000 shares of preferred stock, $0.01 par value per share. The preferred stock was permitted to be issued from time to time in one or more series. Gastar USA’s Board of Directors (the “Gastar USA Board”) was authorized to fix the number of shares of any series of preferred stock and to determine the designation of any such series. The Gastar USA Board was also authorized to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued series of preferred stock and, within the limits and restrictions stated in any resolution or resolutions of the Gastar USA Board originally fixing the number of shares constituting any series, to increase or decrease (but not below the number of shares of any such series outstanding) the number of shares of any series subsequent to the issues shares of that series). Pursuant to the A&R Certificate, the number of shares of preferred stock authorized for issuance was increased to 40,000,000 shares.
	Series A Preferred Stock
	On June 23, 2011, Gastar USA sold an aggregate of 646,295 shares of its 8.625% Series A Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series A Preferred Stock”) through a best efforts underwritten public offering. The net proceeds to Gastar USA were approximately $13.6 million after deducting underwriting discounts, commissions and offering expenses.
	On June 29, 2011, Gastar USA entered into an at-the-market sales agreement (“ATM Agreement”) with McNicoll, Lewis & Vlak LLC (“MLV”). According to the provisions of the ATM agreement, Gastar USA may offer and sell from time to time up to 3,400,000 shares of Series A Preferred Stock through MLV, as its sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between Gastar USA and MLV.
	For the year ended December 31, 2013, Gastar USA sold 6,906 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $136,000, resulting in 3,958,160 total shares of Series A Preferred Stock issued for total net proceeds, inception to date, of $76.8 million at December 31, 2013. From January 1, 2014 to March 11, 2014, Gastar USA sold 26,203 additional shares of Series A Preferred Stock for net proceeds of $628,000.
	The Series A Preferred Stock is subordinated to all of Gastar USA’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. Parent has entered into a guarantee agreement, whereby it will fully and unconditionally guarantee the payment of dividends that have been declared by the board of directors of Gastar USA, amounts payable upon redemption or liquidation, dissolution or winding up, and any other amounts due with respect to the Series A Preferred Stock, to the extent described in the guarantee agreement. Parent’s obligations with respect to the guarantee will be effectively subordinated to all of its existing and future debt.
	The Series A Preferred Stock cannot be converted into common stock of Gastar USA or the Company, but may be redeemed by Gastar USA, at Gastar USA’s option, on or after June 23, 2014 for $25.00 per share plus any accrued and unpaid dividends or in certain circumstances prior to such date as a result of a change in control. Following a change in control, Gastar USA will have the option to redeem the Series A Preferred Stock, in whole but not in part, within 90 days after the date on which the change in control occurs, for cash at the following prices per share, plus accrued and unpaid dividends (whether or not declared), up to the redemption date:
	Redemption Date	Redemption
		Price
	Prior to June 23, 2014	$	25.25
	On or after June 23, 2014	$	25
	There is no mandatory redemption of the Series A Preferred Stock.
	Gastar USA will pay cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the years ended December 31, 2013, 2012 and 2011, Gastar USA paid dividends of $8.5 million, $7.1 million and $1.0 million, respectively.
	Series B Preferred Stock
	On October 29, 2013, Gastar USA sold 2,000,000 shares of its 10.75% Series B Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series B Preferred Stock”), in an underwritten public offering. On November 1, 2013, the underwriters partially exercised their option to purchase additional shares of Series B Preferred Stock and purchased an additional 140,000 shares of Series B Preferred Stock. The issuance of the 2,140,000 shares of Series B Preferred Stock closed on November 7, 2013 with Gastar USA receiving net proceeds of approximately $50.1 million after deducting underwriting commissions and offering expenses.
	The Series B Preferred Stock rank senior to Gastar USA’s common stock and on parity with its 8.625% Series A Cumulative Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of Gastar USA’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock. The Parent has entered into a guarantee agreement, whereby it will fully and unconditionally guarantee the payment of dividends that have been declared by the board of directors of Gastar USA, amounts payable upon redemption or liquidation, dissolution or winding up, and any other amounts due with respect to the Series B Preferred Stock, to the extent described in the guarantee agreement. Parent’s obligations with respect to the guarantee are effectively subordinated to all of its existing and future debt.
	Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at Gastar USA’s option for $25.00 per share in cash. Following a change in ownership or control, Gastar USA will have the option to redeem the Series B Preferred Stock, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If Gastar USA does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into up to and aggregate of 11.5207 shares of Gastar USA’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If Gastar USA exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption. Notwithstanding any of the foregoing, if a change of ownership or control occurs prior to the consummation of the Reorganization Transactions (as defined in the Certificate of Designation), (i) the holders of Series B Preferred Stock shall not have the conversion right described above and (ii) the dividend rate shall increase to 12.75%.
	There is no mandatory redemption of the Series B Preferred Stock.
	Gastar USA will pay cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the year ended December 31, 2013, Gastar USA paid dividends of $847,000.

Equity_Compensation_Plans

Equity Compensation Plans	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Equity Compensation Plans	'
	Equity Compensation Plans
	Share-Based Compensation Plan
	At the annual meeting of stockholders held June 4, 2009, Parent's stockholders approved the first amendment to Parent’s 2006 Long-Term Stock Incentive Plan (the “2006 Plan”) that, effective as of April 1, 2009, merged the Parent’s Stock Option Plan (the “2002 Stock Option Plan”) with and into the 2006 Plan so that all outstanding equity awards and all future equity awards to be made to employees, officers and directors of the Company would be under the 2006 Plan. The merging of the 2002 Stock Option Plan with and into the 2006 Plan resulted in the cessation of the existence of the 2002 Stock Option Plan and the transfer of all shares of common stock previously reserved and available for issuance under the 2002 Stock Option Plan, including any shares of common stock subject to outstanding stock option awards previously granted under the 2002 Stock Option Plan prior to the effective date of the amendments, to the shares of common stock reserved under the 2006 Plan.
	Additionally, the amended 2006 Plan (i) provided that the Compensation Committee of the Parent, at its discretion, may provide, in an award agreement, that an individual who is granted an award under the 2006 Plan (a “participant”) may elect to have shares of common stock withheld from or netted against the total number of shares of common stock otherwise issuable to such participant pursuant to his award in order to pay the exercise or purchase price of such award and/or to satisfy all employer tax withholding obligations with respect to the participant’s award under the 2006 Plan, (ii) clarified that shares of common stock issuable under the 2006 Plan and forfeited back to the 2006 Plan will be deemed not to have been issued under the 2006 Plan and will again be available for the grant of an award under the 2006 Plan, (iii) provided that shares of common stock withheld from or netted against an award granted under the 2006 Plan for payment of (a) the exercise or purchase price of an award and (b) all applicable employer tax withholding obligations associated with an award will be deemed not to have been issued under the 2006 Plan and will again be available for the grant of an award under the 2006 Plan, (iv) provided that the maximum number of shares of common stock that may be subject to stock options, bonus stock awards and stock appreciation rights granted to any one individual during any calendar year may not exceed 200,000 shares of common stock (subject to adjustment pursuant to Section 11(a) of the 2006 Plan) and (v) provide that the definition of “performance criteria” in the 2006 Plan include a criteria relating to the growth of proved natural gas and oil reserves of the Company.
	At the annual meeting of stockholders held June 7, 2012, Parent's stockholders approved the Second Amendment to the 2006 Plan that, effective June 3, 2012, increased the total number of shares of common stock that may be delivered pursuant to the 2006 Plan by 5,000,000 shares and provided that, in any calendar year, any one employee may not be granted more than 1,000,000 shares under all awards granted to such employee.
	The 2006 Plan authorizes Parent’s Board of Directors (the “Parent Board”) to issue stock options, stock appreciation rights, bonus stock awards and any other type of award, which are consistent with the 2006 Plan’s purposes to directors, officers and employees of the Company and its subsidiaries covering a maximum of 11,000,000 million shares of common stock. The contractual lives and vesting periods for grants are determined by the Parent Board at the time a grant is awarded. Recent stock option grants have an expiration of ten years. The vesting schedule for stock option grants has varied from two years to four years but generally has been over a four-year period vesting at 25% per year beginning on the first anniversary date of the grant. Stock options granted pursuant to the 2006 Plan have exercise prices determined by the Parent Board, but an exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock exchange on which Parent’s shares of common stock are listed. The vesting period for recent restricted common stock grants has been from two to four years, but generally has been over three years, vesting annually from the date of grant in equal proportions.
	At December 31, 2013, 1,544,838 shares of common stock of Parent were available for future stock-based compensation grants under the 2006 Plan. All shares of common stock issued upon the exercise of stock option grants or vesting of restricted stock grants are authorized, issued by Parent and are fully paid and non-assessable.
	In connection with the merger, the 2006 Plan was assumed by Gastar Exporation Inc. and, effective as of the merger, was amended, restated and renamed the “Gastar Exploration Inc. Long-Term Incentive Plan” (as amended, the “LTIP”). The LTIP provides for substantially the same terms as the 2006 Plan, except the LTIP provides for awards with respect to Gastar Exploration Inc. common stock rather than Parent common stock. All unexercised and unexpired options to purchase Parent’s common stock, restricted shares of Parent and other rights to acquire Parent common stock under the 2006 Plan (including performance-based units) became options to purchase, restricted stock or other rights to acquire the same number of shares of Gastar Exploration Inc. pursuant to the LTIP, subject to the same terms and conditions, including the per share exercise price (but, in the case of performance awards, performance from and after the effective time of the merger will be determined with respect to the stock price of Gastar Exploration Inc. rather than Parent).
	Determining Fair Value of Stock Options
	In determining the fair value of stock option grants, the Company utilized the following assumptions:
	Valuation and Amortization Method. The Company estimates the fair value of stock option awards using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method.”
	Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding. The Company determined the expected life to be 6.25 years, based on historical information, for all stock options issued with four-year vesting periods and ten-year grant expirations.
	Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Parent's common shares at the beginning of the quarter in which the stock option is granted. The volatility is based on weighted average historical movements of Parent’s common share price on the NYSE MKT LLC over a period that approximates the expected life.
	Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.
	Expected Dividend Yield. Parent has not paid any cash dividends on its common shares and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.
	Expected Forfeitures. Forfeitures of unvested stock options and restricted common shares are calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. For 2013, 2012 and 2011, the Company used forfeiture rates in determining compensation expense of 14%, 15.5% and 8.5%, respectively.
	The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. There were no stock options granted during the years ended December 31, 2013, 2012 and 2011.
	The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated:
		For the Years Ended December 31,
		2013				2012			2011
		(in thousands, except per share data)
	Weighted average grant date fair value per stock option granted	$	—			$	—		$	—
	Intrinsic value of stock options exercised (1)	$	19			$	2		$	18
	Grant date fair value of stock options vested	$	88			$	117		$	282
	_______________
	-1	Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.
	Stock Option Activity
	The following tables summarize certain information related to outstanding stock options under the 2006 Plan as of and for the year ended December 31, 2013:
		Shares			Weighted Average			Weighted Average		Aggregate
					Exercise Price			Remaining		Intrinsic Value
					per Share			Contractual Term		(in thousands)
								(in years)
	Outstanding at December 31, 2012	959,100			$	11.31
	Granted	—			—
	Exercised	(10,000	)		2.6
	Canceled/Expired	—			—
	Forfeited	(75,000	)		8.18
	Outstanding at December 31, 2013	874,100			$	11.68
	Options vested and exercisable at December 31, 2013	864,100			$	11.76		3.17		$	739
		Shares			Weighted Average			Weighted Average				Weighted Average	Aggregate
					Fair Value			Exercise Price				Remaining	Intrinsic Value
					per Share			per Share				Contractual Term	(in thousands)
												(in years)
	Outstanding non-vested options at December 31, 2012	80,725			$	2.07
	Granted	—			—
	Vested	(50,725	)		1.73
	Forfeited	(20,000	)		2.58
	Outstanding non-vested options at December 31, 2013	10,000			$	2.74		$	4.27			0.04	$	27
	There was no unrecognized expense as of December 31, 2013 for all outstanding options.
	Restricted Share Activity
	The following table summarizes information related to restricted shares at December 31, 2013:
		Shares			Weighted  Average			Weighted Average		Aggregate
					Fair Value			Remaining		Intrinsic Value (in thousands)
					per Share			Contractual Term
								(in years)
	Outstanding non-vested restricted shares at December 31, 2012	2,760,446			$	2.75
	Granted	2,288,179			1.3
	Vested	(762,682	)		3.57
	Forfeited	(512,862	)		1.87
	Outstanding non-vested restricted shares at December 31, 2013	3,773,081			$	1.82		8.68		$	26,110
	The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated:
		For the Years Ended December 31,
		2013				2012			2011
	(in thousands, except per share data)
Weighted average grant date fair value per restricted share	$	1.3			$	2.09		$	4.15
Total fair value of restricted shares vested	$	2,725			$	2,492		$	2,436
Unrecognized compensation expense as of December 31, 2013 for all outstanding restricted share awards is $2.0 million and will be recognized over a weighted average period of 1.36 years.
Performance Based Units Activity
Pursuant to the 2006 Plan, as amended, the Company's Compensation Committee agreed to allocate a portion of the 2013 long-term incentive grants to executives as performance based units (“PBUs”). The PBUs represent a contractual right to receive shares of Parent's common stock, an amount of cash equal to the fair market value of a share of Parent's common stock, or a combination of shares of Parent's common stock and cash as of the date of settlement based on the number of PBUs to be settled. The settlement of PBUs may range from 0% to 200% of the targeted number of PBUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PBUs vest equally and settlement is determined annually over a three year period. Any PBUs not vested at each measurement date will expire.
Compensation expense associated with PBUs is based on the grant date fair value of a single PBU as determined using a Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PBUs with shares of Parent's common stock at each measurement date, the PBU awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the PBU award.
The table below provides a summary of PBUs as of the date indicated:
		PBUs			Fair Value per Unit
Unvested PBUs at December 31, 2012		—			$	—
Granted		1,192,889			1.56
Vested		—			—
Forfeited		(127,155	)		—
Unvested PBUs at December 31, 2013		1,065,734			$	1.56
For the year ended December 31, 2013, the Company recognized $931,000 of compensation expense associated with the PBUs granted on January 30, 2013. As of December 31, 2013, the Company had $731,000 of total unrecognized expense for the PBUs.
Stock-Based Compensation Expense
For the years ended December 31, 2013, 2012 and 2011, the Company recorded stock-based compensation expense for restricted shares, PBUs, and stock options granted using the fair-value method of $3.4 million, $3.3 million and $2.6 million, respectively. All stock-based compensation costs were expensed and not tax affected, as the Company currently records no U.S. income tax expense.
As of December 31, 2013, the Company had approximately $2.7 million of total unrecognized compensation cost related to unvested stock options, restricted shares and PBUs, which is expected to be amortized over the following periods:
	Amount
	(in thousands)
2014	$	2,028
2015	594
2016	66
Total	$	2,688

Interest_Expense

Interest Expense	12 Months Ended
	Dec. 31, 2013
Interest Expense [Abstract]	'
Interest Expense	'
	Interest Expense
	The following tables summarize the components of the Company's interest expense for the periods indicated:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Interest expense:
	Cash and accrued	$	14,130		$	1,992		$	682
	Amortization of deferred financing costs (1)(2)	2,322			224			249
	Capitalized interest	(3,284		)	(1,946		)	(818		)
	Total interest expense	$	13,168		$	270		$	113
	_______________________________
	-1	The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. See Note 4, “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.”
	-2	The year ended December 31, 2013 includes $716,000 of debt discount accretion related to the Notes.
	The following tables summarize the components of Gastar USA's interest expense for the periods indicated:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Interest expense:
	Cash and accrued	$	13,978		$	1,993		$	681
	Amortization of deferred financing costs and debt discount (1)(2)	2,322			224			248
	Capitalized interest	(3,284		)	(1,946		)	(817		)
	Total interest expense	$	13,016		$	271		$	112
	_______________________________
	-1	The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. See Note 4, “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.”
	-2	The year ended December 31, 2013 includes $716,000 of debt discount accretion related to the Notes.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	Chesapeake Energy Corporation
	Chesapeake Energy Corporation acquired 6,781,768 of Parent’s common shares during 2005 to 2007 in a series of private placement transactions. On March 28, 2013, the Company entered into a Settlement Agreement between Chesapeake and the Company, Gastar Texas and Gastar Texas LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding common shares of Parent held by Chesapeake upon the closing of the stock repurchase and settlement on June 7, 2013. See Note 8, “Capital Stock - Shares Owned by Chesapeake Energy Corporation.”
	Also on March 28, 2013, the Company entered into the Chesapeake Purchase Agreement, pursuant to which Gastar USA acquired the Chesapeake Assets on June 7, 2013. See Note 3, “Property, Plant and Equipment - Chesapeake Acquisition.”
	As of December 31, 2013, Chesapeake Energy Corporation did not own any of Parent’s outstanding common shares.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated:
		For the Year Ended December 31,
		2013			2012			2011
		(in thousands)
	United States	$	51,276		$	(152,322	)	$	285
	Foreign	(1,934		)	(1,469		)	(1,025		)
	Total income (loss) before income taxes	$	49,342		$	(153,791	)	$	(740	)
	The Company’s income tax expense (benefit) consists of the following:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Current:
	Federal	$	—		$	—		$	—
	State	—			—			—
	Foreign	—			—			—
	Provision for income taxes	$	—		$	—		$	—
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Deferred:
	Federal	$	(15,299	)	$	—		$	—
	State	(743		)	—			—
	Foreign	—			—			—
	Income tax expense (benefit)	$	(16,042	)	$	—		$	—
	The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Expected income tax provision (benefit) at statutory rate	$	11,655		$	(53,827	)	$	(259	)
	State tax, tax effected	96			(2,562		)	—
	Non-deductible stock-based compensation expense	605			560			441
	Tax effect of Canadian tax rate differences	193			(125		)	(103		)
	Loss of Canadian tax attributes due to migration from Canada	19,825			—			—
	Gain on acquisition of assets at fair value	(9,685		)	—			—
	Non-deductible costs of migration from Canada to U.S.	95			—			—
	Other	(49		)	15			10
	Other changes in valuation allowance	(38,777		)	55,939			(89		)
	Actual income tax provision	$	(16,042	)	$	—		$	—
	The components of the Company’s U.S. deferred taxes are as follows:
		As of December 31,
		2013			2012
		(in thousands)
	Deferred tax asset (liability):
	Capital assets	$	(70,955	)	$	(22,668	)
	Net operating loss carry forwards	122,675			93,339
	Foreign tax credit carry forwards	50,681			50,681
	Valuation allowance	(102,401		)	(121,352		)
	Net deferred tax asset	$	—		$	—
	The Company utilized its U.S. net operating loss carry forwards in 2009 due to the U.S. gain recognition on the sale of the Australian Assets. The Company has approximately $333.9 million of net operating loss carry forwards as of December 31, 2013, 2012which, if not utilized, will expire beginning in 2030. For U.S. federal income tax purposes, as of December 31, 2013, the Company has foreign tax credit carry forwards of $50.7 million, which, if not utilized, will expire in 2019. The utilization of the net operating loss carry forward and the foreign tax credit carry forward are dependent on the Company generating future taxable income and U.S. tax liability, as well as other factors.
	Effective November 14, 2013, the Company withdrew from Canada and re-incorporated in Delaware (the “Migration”). As a result of the Migration, the Company's Canadian tax attributes have effectively been forfeited. As all of the Canadian tax attributes were subject to a valuation allowance, the Migration from Canada to the U.S. is not expected to result in any Canadian tax expense. The following tables present the Canadian tax attributes forfeited and the release of the Canadian valuation allowance resulting from the Migration.
		As of December 31,
		2013			2012
		(in thousands)
	Canadian and foreign exploration and development expense	$	—		$	2,597
	Undeducted share issuance costs	$	—		$	1,239
	Undeducted non-capital and capital loss carry forwards	$	—		$	73,522
	The components of Parent’s Canadian deferred tax assets are as follows:
		As of December 31,
		2013			2012
		(in thousands)
	Deferred tax asset:
	Capital assets	$	—		$	649
Share issuance costs	—			310
Tax loss carry forwards	—			18,381
Valuation allowance	—			(19,340		)
Net deferred tax asset	$	—		$	—
Current authoritative guidance requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2013, the Company did not have any unrecognized tax benefits that, if recognized, would affect the effective tax rate.
The Company is subject to examination of income tax filings in the U.S. and various state jurisdictions for the periods 2010 and forward and the foreign jurisdictions of Canada and Australia for the tax periods 2000 and forward due to the Company’s continued loss position in such jurisdictions. The Company was subjected to an audit by the Internal Revenue Service for the taxable period ended December 31, 2009. The audit began in April 2011 and was completed in January 2012 and did not result in any material adjustments or cash payments.
Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	Earnings per Share
	In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.
		For the Years Ended December 31,
		2013		2012			2011
		(in thousands, except per share and share data)
	Net loss attributable to Gastar Exploration, Inc.	$	39,964	$	(160,868	)	$	(1,764	)
	Weighted average shares of common stock outstanding - basic	60,220,115		63,538,362			63,003,579
	Incremental shares from unvested restricted shares	2,869,490		—			—
	Incremental shares from outstanding stock options	26,095		—			—
	Incremental shares from outstanding PBUs	502,701		—			—
	Weighted average shares of common stock outstanding - diluted	63,618,401		63,538,362			63,003,579
	Net loss per share of common stock attributable to Gastar Exploration, Inc. Common Stockholders:
	Basic	$	0.66	$	(2.53	)	$	(0.03	)
	Diluted	$	0.63	$	(2.53	)	$	(0.03	)
	Shares of common stock excluded from denominator as anti-dilutive:
	Unvested restricted shares	3,505		1,831,435			641,606
	Stock options	—		936,967			810,235
	Total	3,505		2,768,402			1,451,841

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments And Contingencies	'
	Commitments and Contingencies
	Contractual Obligations
	Gastar USA leases its office facilities and certain office equipment under non-cancelable operating lease agreements terminating in August 2016. For the years ended December 31, 2013, 2012 and 2011, office lease expense totaled approximately $372,000, $377,000 and $160,000, respectively.
	As of December 31, 2013, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows:
	2014	$	681
	2015	602
	2016	453
	2017	142
	2018	117
		$	1,995
	Litigation
	Chesapeake Exploration L.L.C. (“Chesapeake Exploration”) and Chesapeake Energy Corp.  (“Chesapeake Energy”) v. Gastar Exploration Ltd., Gastar Exploration Texas, LP, and Gastar Exploration Texas, LLC (No. 4:12-cv-2922), United States District Court for the Southern District of Texas, Houston Division.  This lawsuit, filed on October 1, 2012, re-asserted the same claims for rescission of the November 2005 Agreements (as defined below) and for recovery of amounts paid under those agreements that Chesapeake Exploration and Chesapeake Energy (collectively, “Chesapeake”) previously asserted in the cross-action filed against the Company in the Navasota Resources L.P. vs. First Source Texas, Inc., First Source Gas L.P. (now Gastar Exploration Texas, LP) and Gastar Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas12th Judicial District (“Navasota”) litigation, as previously disclosed in the Company's filings. In March 2011, Chesapeake dismissed its cross-claims against the Company in the Navasota litigation, without prejudice to their re-filing. In the new lawsuit, Chesapeake re-asserted those claims, seeking rescission of (a) a Purchase and Sale and Exploration and Development Agreement between the Company and Chesapeake Exploration Limited Partnership (the “Purchase and Sale Agreement”), relating to properties in the Hilltop Prospect in Texas, (b) an Exploration and Development Agreement between the Company and Chesapeake Exploration Limited Partnership, (c) a Common Share Purchase Agreement between the Company and Chesapeake Energy, and (d) a Registration Rights Agreement between the Company and Chesapeake Energy, all effective as of November 4, 2005 (collectively, “the November 2005 Agreements”), based on an alleged “mutual mistake” and alleged failure of consideration.  Chesapeake alleged that the parties to the November 2005 Agreements believed that the Gastar defendants had the right to convey to Chesapeake Exploration the properties that were the subject of the Purchase and Sale Agreement, notwithstanding the exercise by Navasota Resources LP (“Navasota”) of a preferential right to purchase the interest in the Hilltop Prospect properties. The dispute over the validity of Navasota's exercise of its preferential right to purchase was the subject of litigation filed by Navasota prior to the execution of the November 2005 Agreements.  Chesapeake claims that the Texas Court of Appeals' subsequent ruling in that litigation upholding the validity of Navasota's exercise of the preferential right to purchase established that there was a mutual mistake of fact and a failure of consideration with regard to the November 2005 Agreements. In the alternative, Chesapeake claimed that the Gastar defendants had been unjustly enriched at the expense of Chesapeake by the funds paid by Chesapeake to the Gastar defendants. In their complaint filed in the lawsuit, Chesapeake offered to return Parent's common shares purchased pursuant to the Common Stock Purchase Agreement, and sought restitution from the Gastar defendants of the net amount of approximately $101.4 million, which included the $76.0 million that Chesapeake Energy paid for Parent's common shares (now 5,430,329 shares after a 1:5 stock split) that Chesapeake Energy purchased in 2005 and now seeks to return.  In a motion to compel arbitration filed by Chesapeake on October 24, 2012, Chesapeake asked the court to order arbitration of the claims asserted in the complaint pursuant to an arbitration clause in the Common Share Purchase Agreement.
	The Gastar defendants responded to the lawsuit by filing a motion to dismiss, contending that the claims failed as a matter of law.  Specifically, the Gastar defendants contended in the motion to dismiss that all facts relating to the Navasota claim were fully known to the parties at the time of execution of the November 2005 Agreements, and the parties expressly agreed in the Purchase and Sale Agreement that Chesapeake Exploration would take title to the properties subject to Navasota's claim and would convey the properties to Navasota in the event Navasota prevailed in the litigation, precluding Chesapeake's claims for rescission of the November 2005 Agreements.  For the same reasons, the Gastar defendants also contended in the motion to dismiss that Chesapeake received all of the consideration that the November 2005 Agreements called for and that there was no failure of consideration.  With regard to Chesapeake's alternative unjust enrichment claim, the Gastar defendants contended in the motion to dismiss that it is barred by the two-year statute of limitations and that in any event, it failed for a variety of reasons, including the fact that the parties' agreements address the subject matter of the dispute (precluding a claim for unjust enrichment) and the fact that the Gastar defendants were not unjustly enriched by Chesapeake Exploration's payment of the share of costs attributable to an interest in the properties that was not owned by the Gastar defendants.   The Gastar defendants also contended in their response to the motion to compel arbitration that Chesapeake's claims are not subject to arbitration and that the claims should be resolved on the merits by the federal court in which Chesapeake filed the lawsuit.
	On March 28, 2013, the Company entered into a Settlement Agreement between Chesapeake and the Gastar defendants (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Gastar defendants settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in the Chesapeake lawsuit. In order to affect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding common shares of the Company currently held by Chesapeake Energy Corporation.
	On the same day that the Company entered into the Settlement Agreement, Gastar USA entered into an agreement for the acquisition of certain properties from Chesapeake. The closing of the proposed property acquisition, stock repurchase and settlement for an adjusted aggregate cash payment of $80.0 million, comprised of approximately $69.4 million in property acquisition costs (subject to adjustment for an acquisition effective date of October 1, 2012), stock repurchase price of approximately $9.8 million and an additional $1.0 million for litigation settlement occurred on June 7, 2013. On March 31, 2013, following notification to the Court regarding the execution of the settlement agreement, the Court in the Chesapeake lawsuit entered an order of dismissal, without prejudice to the right of counsel of record to move for reinstatement of the case within 90 days in the event the settlement is not consummated.
	The acquisition transaction closed on June 7, 2013, and the payments described above were made as provided in the Settlement Agreement and the agreement for acquisition of properties from Chesapeake. Thereafter, the parties to the Chesapeake lawsuit filed a stipulation of dismissal of prejudice, and on June 11, 2013, the court entered an order dismissing the case with prejudice.
	Gastar Exploration USA, Inc., et al v. Williams Ohio Valley Midstream LLC (American Arbitration Association Matter No. 70-198-Y-00461-13). On July 16, 2013, Gastar USA and two similarly situated co-claimants initiated an arbitration proceeding against Williams Ohio Valley Midstream LLC (“Williams OVM”). The claimants allege that Williams OVM has breached various agreements relating to the gathering, processing and marketing of natural gas, NGLs and condensate produced from properties that are owned in part by Gastar USA in the Marcellus Shale in Marshall and Wetzel Counties, West Virginia, and request that an Arbitration Panel assess an unspecified amount of damages against Williams OVM for, among other claims, failure to timely construct certain gathering and processing facilities, maximize the net value of produced condensation, and fractionate and purchase NGLs as provided in the agreements. On August 7, 2013, Williams OVM filed an answering statement and counterclaim for damages in excess of $612,000 in the arbitration matter. On December 31, 2013, the parties informed the Arbitration Panel that they have reached an agreement in principle to settle their disputes. The settlement is subject to final documentation, which has not yet been completed. At the request of both parties, on January 9, 2014, the Arbitration Panel stayed all proceedings, pending completion of the final settlement documentation.
	Gastar Exploration Ltd vs U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No. 2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage are $20.0 million. The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012. The Company appealed the District Court ruling and on July 15, 2013, the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The insurers filed a motion for reconsideration in the Court of Appeals, which that court denied. The insurers are seeking discretionary review from the Texas Supreme Court, and their petition for review was filed on February 18, 2014. The petition becomes ripe for review thirty days after that. If none of the justices votes for any action, then the petition is denied automatically thirty-one days after the justices received it (61 days from filing date). If the Texas Supreme Court denies review or affirms the Fourteenth Court of Appeals’ ruling, the case will be remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of whether the Company's claims are securities claims covered by the insuring agreements.
	The Company has been expensing legal defense costs on these proceedings as they are incurred.
	The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
	Commitments
	In March 2008, Gastar USA entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of Gastar USA's natural gas production from the Hilltop area of East Texas (the “ETC Contract”). The ETC Contract was effective September 1, 2007 and had a term of 10 years. Prior to the sale of the Company's interest in the East Texas properties, ETC provided Gastar USA 50.0 MMcf per day of treating capacity and 150.0 MMcf/d of transportation capacity of production from Gastar USA’s wells, located in Leon and Robertson Counties, Texas. Upon the sale of the Company's interest in the East Texas properties on October 2, 2013, the purchaser of the East Texas properties assumed the contractual obligations under the ETC Contract.
	On November 16, 2009, concurrent with Gastar USA’s sale of its Hilltop Gathering System, Gastar Texas entered into the Hilltop Gathering Agreement effective November 1, 2009, with Hilltop Resort for an initial term of 15 years. Prior to the Company's sale of its interest in the East Texas properties, the Hilltop Gathering Agreement covered delivery of Gastar USA’s gross production of natural gas in the Hilltop area of East Texas to certain delivery points provided under the ETC Contract. Gastar USA was also obligated to connect new wells that it drilled within the area covered by the Hilltop Gathering Agreement to the Hilltop Gathering System. The Hilltop Gathering Agreement provided for a minimum quarterly gathering gross production volume of 50.0 MMcf/d (35.0 MMcf/d net to Gastar USA) times the number of days in the quarter for five years from the effective date of November 1, 2009. If quarterly production was less than the minimum quarterly requirement, the gathering fee was payable on such deficit. If excess quarterly production existed, such excess was carried forward to be used to offset any future deficit quarters. The gathering fee on the initial gross 25.0 Bcf of production was $0.325 per Mcf, reducing in steps to $0.225 per Mcf when cumulative gross production reached 300.0 Bcf. For the year ended December 31, 2013, Gastar USA paid $1.8 million to Hilltop Resort as a result of actual production volumes being less than minimum contractual volume requirements. Upon the sale of the Company's interest in the East Texas properties on October 2, 2013, the purchaser of the East Texas properties assumed any future minimum volume requirement obligations under the Hilltop Gathering Agreement.
	During December 2010, we, along with Atinum, entered into a gas purchase agreement with SEI Energy, LLC (“SEI”) with respect to our Marshall County, West Virginia production. The initial term of the gas purchase agreement is five years with the option to extend the term of the gas purchase agreement for an additional five year period. Our Marshall County, West Virginia production is dedicated to SEI for the term of the gas purchase agreement. SEI will purchase all hydrocarbon production, including all natural gas, condensate and natural gas liquids. SEI has an agreement to utilize the Williams Ohio Valley Midstream LLC (“Williams") midstream facilities (formerly owned by Caiman Energy Midstream, LLC), including its 520.0 MMcf/d Fort Beeler processing plant located in Marshall County, West Virginia for transporting and processing. In order to secure access to the Williams facilities, we, Atinum and SEI dedicated all hydrocarbons purchased and produced in Marshall County, West Virginia for a term of ten years.
	Restoration, Removal and Environmental Liabilities
	The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year. At December 31, 2013, the Company had total liabilities of $6.1 million related to asset retirement obligations of which $633,000 is recorded as short-term liabilities and $5.4 million is recorded as long-term liabilities. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 5, “Asset Retirement Obligation.”
	Indemnifications
	Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if any, is difficult to predict.
	Employment Agreements
	The Company entered into employment agreements with its Chief Executive Officer and its Chief Financial Officer, effective February 24, 2005 (as amended July 25, 2008 and February 3, 2011) and May 17, 2005 (as amended July 25, 2008 and April 10, 2012), respectively. The agreements set forth, among other things, annual compensation, and adjustments thereto, bonus payments, fringe benefits, termination and severance provisions. The agreements renew annually; however, they may be terminated at any time with or without cause.
	The Company also has entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to indemnify them to the fullest extent permitted by law against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to the beneficiary of such indemnification agreements.

Concentration_of_Risk_and_Sign

Concentration of Risk and Significant Customers	12 Months Ended
	Dec. 31, 2013
Risks and Uncertainties [Abstract]	'
Concentration of Risk and Significant Customers	'
	Concentration of Risk and Significant Customers
	The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated:
			For the Years Ended December 31,
			2013		2012		2011
	Marcellus Shale and Other Appalachia		65	%	72	%	15	%
	Mid-Continent		26	%	—	%	—	%
	Hilltop Area, East Texas (1)		9	%	27	%	79	%
	Powder River Basin (2)		—	%	1	%	6	%
	__________________
	-1	The Company's working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013.
	-2	The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012.
	The following table provides information regarding our significant customers and the percentages of oil, condensate, natural gas and NGLs revenues, excluding hedge impact, which they represented for the periods indicated:
			For the Years Ended December 31,
			2013		2012		2011
	SEI		56	%	47	%	8	%
	Sunoco		16	%	—	%	—	%
	Clearfield Appalachian		8	%	14	%	—	%
	ETC		8	%	24	%	69	%
	Plains Marketing LP		1	%	2	%	10	%
	SEI and Clearfield Appalachian purchase the majority of the Company's Marcellus Shale and Other Appalachia production. There are limited oil, condensate, natural gas and NGLs purchase and transportation alternatives currently available in Appalachia. If SEI or Clearfield Appalachian were to cease purchasing and transporting the Company’s Marcellus Shale and Other Appalachia oil, condensate, natural gas and NGLs production and the Company was unable to obtain timely access to existing or future facilities on acceptable terms, or in the event of any significant change affecting these facilities, including delays in the commencement of operations of any new pipelines or the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise, the Company’s ability to conduct normal operations would be restricted. SEI and Sunoco purchase the majority of the Company's Mid-Continent production. There are numerous purchase and transportation alternatives currently available in the Mid-Continent so in the event that SEI or Sunoco were to cease purchasing and transporting our oil, condensate, natural gas and NGLS production, the Company's ability to conduct normal operations would not be significantly restricted. Prior to the Company's sale of its interest in East Texas, ETC treated, transported and purchased substantially all of the Company’s East Texas natural gas production and Plains Marketing LP purchased substantially all of the Company's East Texas oil production.

Statement_Of_Cash_Flows_Supple

Statement Of Cash Flows - Supplemental Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Statement Of Cash Flows - Supplemental Information	'
	Statement of Cash Flows – Supplemental Information
	The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	7,341		$	39		$	—
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued drilling costs	$	582		$	4,666		$	4,600
	Capital expenditures excluded from accounts receivable	(4,077		)	(929		)	—
	Capital expenditures excluded from prepaid expenses	—			—			48
	Asset retirement obligation included in natural gas and oil properties	(1,302		)	1,164			492
	Asset retirement obligation sold/assigned to operator	(4,354		)	(2,227		)	—
	Application of advances to operators	19,755			7,441			6,529
	Other	47			(36		)	—
	The following is a summary of Gastar USA's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:
		For the Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	7,341		$	39		$	—
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued costs	$	582		$	4,666		$	4,600
	Capital expenditures excluded from accounts receivable	(4,077		)	(929		)	—
	Capital expenditures excluded from prepaid expenses	—			—			48
	Asset retirement obligation included in natural gas and oil properties	(1,302		)	1,164			492
	Asset retirement obligation assigned to operator	(4,354		)	(2,227		)	—
	Application of advances to operators	19,755			7,441			6,529
	Due to (from) Parent - transfer to equity, net	15,495			5,295			2,612
	Other	47			(36		)	—

Quarterly_Consolidated_Financi

Quarterly Consolidated Financial Data - Unaudited	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Consolidated Financial Data - Unaudited	'
	Quarterly Consolidated Financial Data – Unaudited
	The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2013 and 2012:
		2013
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	11,264		$	30,926		$	18,840		$	26,725
	Income (loss) from operations	(1,849		)	13,809			1,626			5,178
	Income (loss) before provision for income taxes (1)	(2,456		)	53,970			(1,808		)	(16,406		)
	Net income (loss)	(2,456		)	53,970			(1,808		)	(364		)
	Dividend on preferred stock attributable to non-controlling interest	2,130			2,134			2,134			2,980
	Net income (loss) attributable to Gastar Exploration, Inc.	(4,586		)	51,836			(3,942		)	(3,344		)
	Net income (loss) per share of common stock attributable to Gastar Exploration, Inc. Common Stockholders:
	Basic	$	(0.07	)	$	0.83		$	(0.07	)	$	(0.06	)
	Diluted	$	(0.07	)	$	0.81		$	(0.07	)	$	(0.06	)
	Weighted average shares of common stock outstanding:
	Basic	63,864,527			62,398,472			57,359,357			57,433,550
	Diluted	63,864,527			63,813,423			57,359,357			57,433,550
	_______________
	-1	Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.
		2012
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	9,154		$	13,921		$	9,443		$	17,422
	Income (loss) from operations (1)	(5,052		)	(72,237		)	(81,443		)	5,245
	Income (loss) before provision for income taxes	(5,074		)	(72,308		)	(81,473		)	5,064
	Net income (loss)	(5,074		)	(72,308		)	(81,473		)	5,064
	Dividend on preferred stock attributable to non-controlling interest	1,236			1,727			1,984			2,130
	Net income (loss) attributable to Gastar Exploration, Inc	(6,310		)	(74,035		)	(83,457		)	2,934
	Net income (loss) per share of common stock attributable to Gastar Exploration, Inc. Common Stockholders:
	Basic	$	(0.10	)	$	(1.17	)	$	(1.31	)	$	0.05
	Diluted	$	(0.10	)	$	(1.17	)	$	(1.31	)	$	0.05
	Weighted average shares of common stock outstanding:
	Basic	63,336,437			63,541,739			63,601,645			63,669,744
	Diluted	63,336,437			63,541,739			63,601,645			63,678,597
	_______________
	-1	Loss from operations for the second and third quarters of 2012 include a quarterly ceiling test impairment charge of $72.7 million and $78.1 million, respectively.
	The following tables summarize Gastar USA’s results of operations by quarter for the years ended December 31, 2013 and 2012:
		2013
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	11,264		$	30,926		$	18,840		$	26,725
	Income (loss) from operations (1)	(1,628		)	14,157			2,086			5,957
	Income (loss) before provision for income taxes	(2,231		)	54,312			(1,363		)	(15,483		)
	Net income (loss)	(2,231		)	54,312			(1,363		)	559
	Dividends on preferred stock	2,130			2,134			2,134			2,980
	Net income (loss) attributable to common stockholder	(4,361		)	52,178			(3,497		)	(2,421		)
	_______________
	-1	Income before provision for income taxes for the second quarter of 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.
		2012
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	9,154		$	13,921		$	9,443		$	17,422
	Income (loss) from operations (1)	(4,662		)	(71,980		)	(80,973		)	5,566
	Income (loss) before provision for income taxes	(4,686		)	(72,011		)	(81,007		)	5,382
	Net income (loss)	(4,686		)	(72,011		)	(81,007		)	5,382
	Dividend on preferred stock	1,236			1,727			1,984			2,130
	Net income (loss) attributable to common stockholder	(5,922		)	(73,738		)	(82,991		)	3,252
	_______________
	-1	Loss from operations for the second and third quarters of 2012 include a quarterly ceiling test impairment charge of $72.7 million and $78.1 million, respectively.

Supplemental_Oil_and_Gas_Discl

Supplemental Oil and Gas Disclosures - Unaudited	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Supplemental Oil and Disclosures - Unaudited	'
	Supplemental Oil and Gas Disclosures – Unaudited
	Capitalized Costs Relating Oil and Producing Activities
	The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities for the periods indicated:
		As of December 31,
		2013				2012				2011
		(in thousands)
	Proved properties:
	United States	$	935,773			$	671,193			$	514,357
	Total proved properties	935,773				671,193				514,357
	Unproved properties:
	United States	96,220				67,892				78,302
	Total unproved properties	96,220				67,892				78,302
	Total natural gas and oil properties	1,031,993				739,085				592,659
	Less:
	Impairment of proved natural gas and oil properties
	United States	(337,939		)		(337,939		)		(187,152		)
	Accumulated depreciation, depletion and amortization	(177,790		)		(145,631		)		(120,436		)
	Net capitalized costs	$	516,264			$	255,515			$	285,071
	Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs of approximately $3.4 million, $4.8 million and $5.8 million at December 31, 2013, 2012 and 2011, respectively.
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
	The following table sets forth costs incurred related to the Company’s oil and natural gas activities in the U.S. for the periods indicated:
			For the years ended December 31,
			2013				2012				2011
			(in thousands)
	Property acquisition
	Proved (1)		$	189,594			$	—			$	—
	Unproved (2)		71,472				25,676				19,552
	Exploration		36,893				10,041				47,668
	Development		53,058				111,878				18,167
	Total costs incurred		$	351,017			$	147,595			$	85,387
	_______________
	-1	The 2013 property acquisition costs excludes a downward adjustment of $2.6 million for fair value of acquisition.
	-2	The 2013 property acquisition costs excludes $46.3 million of adjustment for fair value of acquisition.
	Results of Operations for Oil and Natural Gas Producing Activities
	The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated:
		For the Year Ended December 31,
		2013				2012				2011
		(in thousands, except per Mcfe data)
	Oil, condensate, natural gas and NGLs sales, including commodity derivatives	$	87,755			$	49,940			$	40,235
	Production expenses	(18,113		)		(13,408		)		(13,751		)
	Impairment of oil and natural gas properties	—				(150,787		)		—
	Depreciation, depletion and amortization	(32,158		)		(25,195		)		(14,989		)
	Results of producing activities	$	37,484			$	(139,450	)		$	11,495
	Depreciation, depletion and amortization per Mcfe	$	1.66			$	1.9			$	1.95
	Depreciation, depletion and amortization per MBoe	$	9.94			$	11.41			$	11.7
	The results of producing activities exclude interest charges and general corporate expenses and represent U.S. activities only.
	In accordance with current authoritative guidance, estimates of the Company’s proved reserves and future net revenues are made using benchmark prices, before lease adjustments, that are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil as of December 31, 2013 and 2012. The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves:
		As of December 31,
		2013				2012
	Natural gas (per MMBtu):
	Henry Hub	$	3.67			$	2.76
	Oil (per Bbl):
	WTI posting	$	—			$	91.21
	WTI spot	$	96.78			94.71
	These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas prices and oil prices, which have fluctuated significantly in recent years.
	Net Proved and Proved Developed Reserve Summary
	Reserve Estimation. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2013, 2012, and 2011 and includes reserve information for the Marcellus Shale as of December 31, 2013, 2012, and 2011, reserve information for the Mid-Continent as of December 31, 2013 and reserve information for the Hilltop Area of East Texas as of December 31, 2012 and 2011. The Company sold its working interest in the Hilltop Area of East Texas on October 2, 2013,with an effective date of January 1, 2013. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e., prices and costs as of the date the estimate is made). Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. The Company’s proved developed and proved undeveloped reserves are located only in the U.S.
	The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2013, 2012 and 2011:
	Change in Proved Reserves	Natural  Gas			NGLs			Condensate and Oil			MMcfe (1)		MBoe (4) Equivalents (5)
		(MMcf) (1)			(MBbl) (2)			(MBbl) (2)			Equivalents  (3)
	Proved reserves as of December 31, 2010	49,892			—			61			50,260		8,376
	2011 Activity:
	Extensions and discoveries	56,364			2,767			1,945			84,634		14,106
Revisions of previous estimates (6)	(7,286	)		11			(45	)		(7,494	)	(1,248	)
Production	(7,318	)		(21	)		(40	)		(7,684	)	(1,281	)
Proved reserves as of December 31, 2011	91,652			2,757			1,921			119,716		19,953
2012 Activity:
Extensions and discoveries (7)	57,835			2,783			2,439			89,169		14,861
Revisions of previous estimates	(6,518	)		(348	)		(796	)		(13,375	)	(2,230	)
Production	(10,564	)		(270	)		(177	)		(13,247	)	(2,208	)
Purchases in place	—			—			7			41		7
Sales in place	(1,395	)		—			—			(1,395	)	(231	)
Proved reserves as of December 31, 2012	131,010			4,922			3,394			180,909		30,152
2013 Activity:
Extensions and discoveries (8)	52,750			2,306			4,385			92,897		15,483
Revisions of previous estimates	8,114			714			(337	)		10,375		1,729
Production	(13,366	)		(494	)		(515	)		(19,417	)	(3,237	)
Purchases in place	26,961			2,350			7,796			87,832		14,639
Sales in place	(24,759	)		—			(5	)		(24,791	)	(4,132	)
Proved reserves as of December 31, 2013	180,710			9,798			14,718			327,805		54,634
_______________
-1	Million cubic feet or million cubic feet equivalent, as applicable
-2	Thousand barrels
-3	Oil, condensate and NGLs volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one barrel of oil, condensate or NGLs.
-4	Thousand barrels of oil, condensate or NGLs equivalent.
-5	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
-6	The 2011 downward revision of previous estimates of natural gas is primarily attributed to the decision to forgo an East Texas PUD location due to low natural gas prices which would have resulted in drilling beyond the five-year maximum carry period.
-7	The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery.
-8	74% of the 2013 extensions and discoveries resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
Proved Developed and Undeveloped Reserves	Natural Gas			NGLs			Condensate and Oil			MMcfe (1)		MBoe (4) Equivalents (5)
	(MMcf) (1)			(MBbl) (2)			(MBbl) (2)			Equivalents (3)
31-Dec-11
Proved developed reserves	65,061			1,339			904			78,518		13,087
Proved undeveloped reserves	26,591			1,418			1,017			41,198		6,867
Total	91,652			2,757			1,921			119,716		19,954
31-Dec-12
Proved developed reserves	95,602			3,215.80			1,959			126,653		21,109
Proved undeveloped reserves	35,408			1,706			1,435			54,256		9,042
Total	131,010			4,922			3,394			180,909		30,151
31-Dec-13
Proved developed reserves	114,195			6,025			5,834			185,349		30,892
Proved undeveloped reserves	66,515			3,773			8,884			142,456		23,742
Total	180,710			9,798			14,718			327,805		54,634
_______________
-1	Million cubic feet or million cubic feet equivalent, as applicable
-2	Thousand barrels
-3	Oil, condensate and NGLs volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one barrel of oil, condensate or NGLs.
-4	Thousand barrels of oil, condensate or NGLs equivalent.
-5	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented.
For the years ended December 31, 2013, 2012 and 2011 future cash inflows were computed using the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil (the “benchmark base prices”). For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations:
	For the Years Ended December 31,
	2013				2012				2011
Natural gas, per MMBtu
Henry Hub	$	3.67			$	2.76			$	4.12
Oil, per barrel:
WTI posting	$	—			$	91.21			$	75.96
WTI spot	$	96.78			$	94.71			$	—
These benchmark base prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. The Company also includes its standard overhead charges pursuant to the respective property joint operating agreements in the calculation of its future cash flows.
The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate could also result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or changes in regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is presented below:
	United States
	(in thousands)
December 31, 2011:
Future cash inflows	$	584,067
Future production costs	(101,938		)
Future development costs	(57,843		)
Future income taxes	(33,732		)
Future net cash flows	390,554
10% annual discount for estimated timing of cash flows	(177,771		)
Standardized measure of discounted future cash flows	$	212,783
December 31, 2012:
Future cash inflows	$	672,142
Future production costs	(167,864		)
Future development costs	(83,697		)
Future income taxes (1)	—
Future net cash flows	420,581
10% annual discount for estimated timing of cash flows	(213,772		)
Standardized measure of discounted future cash flows	$	206,809
December 31, 2013:
Future cash inflows	$	2,103,023
Future production costs	(588,568		)
Future development costs	(296,666		)
Future income taxes	(76,701		)
Future net cash flows	1,141,088
10% annual discount for estimated timing of cash flows	(625,259		)
Standardized measure of discounted future cash flows	$	515,829
_______________
-1	No future taxes payable has been included in the determination of discounted future net cash flows for 2012 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The principal sources of changes in the standardized measure of future net cash flows are as follows:
	United States
	(in thousands)
December 31, 2010	$	67,282
Extensions and discoveries, less related costs	180,539
Sale of natural gas and oil, net of production costs	(24,148		)
Revisions of previous quantity estimates	(9,323		)
Net change in income tax	(4,334		)
Net change in prices and production costs	12,394
Accretion of discount	5,011
Development costs incurred	1,482
Net change in estimated future development costs	4,541
Change in production rates (timing) and other	(20,661		)
December 31, 2011	$	212,783
Extensions and discoveries, less related costs	112,390
Sale of natural gas and oil, net of production costs	(29,110		)
Purchases of reserves in place	64
Sales of reserves in place	(216		)
Revisions of previous quantity estimates	(30,959		)
Net change in income tax	4,334
Net change in prices and production costs	(98,589		)
Accretion of discount	1,152
Development costs incurred	19,702
Net change in estimated future development costs	2,518
Change in production rates (timing) and other	12,740
December 31, 2012	$	206,809
Extensions and discoveries, less related costs	196,448
Sale of natural gas and oil, net of production costs	(74,394		)
Purchases of reserves in place	247,208
Sales of reserves in place	(9,063		)
Revisions of previous quantity estimates	6,191
Net change in income tax	(76,701		)
Net change in prices and production costs	79,820
Accretion of discount	1,211
Development costs incurred	23,567
Net change in estimated future development costs	(97,461		)
Change in production rates (timing) and other	12,194
December 31, 2013	$	515,829

Recovered_Sheet1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis of Presentation	'
	Basis of Presentation
	These financial statements are a combined presentation of the consolidated financial statements of the Company and Gastar USA, as predecessors to Gastar Exploration Inc., in satisfaction of Rule 12g-3(g) of the Securities Exchange Act of 1934. Separate information is provided for the Company and Gastar USA as required. Except as otherwise noted, there are no material differences between the consolidated information for the Company presented herein and the consolidated information of Gastar USA.
	The consolidated financial statements of the Company and Gastar USA are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved natural gas and oil reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows. See Note 18, “Supplemental Oil and Gas Disclosures.”
Reclassifications	'
	Reclassifications
	Certain reclassifications of prior year balances have been made to conform to current year presentation; these reclassifications have no impact on net income (loss).
Subsequent Events	'
	Subsequent Events
	In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate.
Principles of Consolidation	'
	Principles of Consolidation
	The consolidated financial statements of the Company include the accounts of Parent and the consolidated accounts of all its subsidiaries. The wholly-owned subsidiaries included in these consolidated accounts are Gastar USA, Gastar Exploration Texas, Inc. (“Gastar Texas, Inc.”), Gastar Exploration Texas LP (“Gastar Texas”), Gastar Exploration Texas LLC (“Gastar Texas LLC”), Gastar Exploration New South Wales, Inc. (“Gastar New South Wales”), and prior to 2012, Gastar Exploration Victoria, Inc. (“Gastar Victoria”). All significant inter-company accounts and transactions have been eliminated in consolidation.
	The consolidated financial statements of Gastar USA include the accounts of Gastar USA and the consolidated accounts of all its subsidiaries. The wholly-owned subsidiaries included in these consolidated accounts are Gastar Texas, Inc., Gastar Texas, Gastar Texas LLC, Gastar New South Wales, and prior to 2012, Gastar Victoria. All significant inter-company accounts and transactions have been eliminated in consolidation.
Use of estimates in Preparation of Financial Statements	'
	Use of estimates in Preparation of Financial Statements
	The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate , natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $32.4 million and $8.9 million as of December 31, 2013 and 2012, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.
Accounts Receivable	'
	Accounts Receivable
	Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties
	The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center.
	Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.
	Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations.
	In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.
	The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2013 and 2012 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. The previous rules required that reserve estimates be calculated using year-end pricing.
	Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered.
	The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted.
Asset Retirement Obligation	'
	Asset Retirement Obligation
	Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations.
Furniture and Equipment	'
	Furniture and Equipment
	Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years.
Capitalized Interest	'
	Capitalized Interest
	The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The primary debt instrument included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2013 was the Notes. Currently, the Company only capitalizes interest on the Notes. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value.
Deferred Financing Costs	'
	Deferred Financing Costs
	Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense.
Derivative Instruments and Hedging Activity	'
	Derivative Instruments and Hedging Activity
	The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.”
	The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in (loss) gain on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in (loss) gain on commodity derivatives contracts in the Company’s consolidated statement of operations.
Stock-Based Compensation	'
	Stock-Based Compensation
	The Company reports compensation expense for restricted common stock, performance based units (“PBUs”) and stock options granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.
	Stock-based compensation cost for restricted shares is estimated at the grant date based on the award's fair value, which is equal to the prior day's closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant based on the award's fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. The Company did not award any stock option grants during 2013, 2012 or 2011.
Treasury Stock	'
	Treasury Stock
	Treasury stock purchases are recorded at cost as a reduction to common stock. Shares of common stock are canceled upon repurchase.
Revenue Recognition	'
	Revenue Recognition
	The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company's NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company's wet gas production. The Company's reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which the Company is credited under its sales contracts. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2013 and 2012.
	The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, oil, condensate, natural gas and NGLs volumes sold are not significantly different from the Company’s share of production.
	The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet.
Deferred Income Taxes	'
	Deferred Income Taxes
	Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. 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. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.
Comprehensive Income	'
	Comprehensive Income
	Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Company has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.
Earnings or Loss per Share	'
	Earnings or Loss per Share
	Basic earnings or loss per share is computed on the basis of the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed based upon the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of stock options, unvested restricted shares and PBUs.
Joint Venture Operations	'
	Joint Venture Operations
	The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Industry Segment and Geographic Information	'
	Industry Segment and Geographic Information
	The Company operates in one industry segment, which is the exploration, development and production of natural gas and oil. Historically, the Company’s operational activities have been conducted in the U.S. and Australia, with only the U.S. having revenue generating operating results. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.
Foreign Currency Exchange	'
	Foreign Currency Exchange
	The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the Company is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction.
	All of the Company’s operations are conducted in U.S. dollars. Prior to July 2009, the Company conducted natural gas property development in Australia; however, prior to reaching commercial operations, these assets were sold. The Company owns non-operating working interests in two gas wells located in Alberta, Canada, from which it has received no revenue since January 1, 2012.
	The Australian and Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of the activity related to the allowance for doubtful accounts	'
	A summary of the activity related to the allowance for doubtful accounts is as follows:
		For the years ended December 31,
		2013			2012			2011
		(in thousands)
	Allowance for doubtful accounts, beginning of year	$	546		$	551		$	571
	Expense	—			—			—
	Reductions/write-offs	(39		)	(5		)	(20		)
	Allowance for doubtful accounts, end of year	$	507		$	546		$	551
Schedule of deferred charges and accumulated amortization	'
	The following table indicates deferred charges and related accumulated amortization as of the dates indicated:
		As of December 31,
		2013			2012
	Deferred charges	$	3,269		$	2,525
	Accumulated amortization	(319		)	(1,689		)
	Deferred charges, net	$	2,950		$	836

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Business Acquisition [Line Items]	'
Property, Plant and Equipment	'
	The Company's total property, plant and equipment consists of the following:
		December 31,
		2013				2012
		(in thousands)
	Oil and natural gas properties, full cost method of accounting:
	Unproved properties	$	96,220			$	67,892
	Proved properties	935,773				671,193
	Total oil and natural gas properties	1,031,993				739,085
	Furniture and equipment	2,691				1,925
	Total property and equipment	1,034,684				741,010
	Impairment of proved natural gas and oil properties	(337,939		)		(337,939		)
	Accumulated depreciation, depletion and amortization	(179,232		)		(146,820		)
	Total accumulated depreciation, depletion and amortization	(517,171		)		(484,759		)
	Total property and equipment, net	$	517,513			$	256,251
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	'
	The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:
		December 31,
		2013				2012
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	4,774			$	1,902
	Acreage acquisition costs	86,097				62,395
	Capitalized interest	5,349				3,595
	Total unproved properties excluded from amortization	$	96,220			$	67,892
Schedule of Relevant Assumptions Used in Ceiling Test Computations	'
	The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted:
			2013
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu) (1)						$	3.67		$	3.61	$	3.44	$	2.95
	West Texas Intermediate oil price (per Bbl) (1)						$	96.78		$	91.69	$	88.13	$	89.17
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
			2012
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu) (1)						$	2.76		$	2.83	$	3.15	$	3.73
	West Texas Intermediate oil price (per Bbl) (1)						$	91.21		$	91.48	$	92.17	$	94.65
	Impairment recorded (pre-tax) (in thousands)		$	150,787			$	—		$	78,054	$	72,733	$	—
			2011
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu) (1)						$	4.12		$	4.16	$	4.21	$	4.1
	West Texas Intermediate oil price (per Bbl) (1)						$	92.71		$	91	$	86.6	$	80.04
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
	_________________________________
	-1	For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.
Chesapeake Assets	'
Business Acquisition [Line Items]	'
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	'
	The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Chesapeake Acquisition (in thousands):
	Consideration:
	Cash consideration		$	69,371
	Fair Value of Liabilities Assumed:
	Deferred tax liability		16,042
	Total purchase price plus liabilities assumed		$	85,413
	Estimated Fair Value of Assets Acquired:
	Unproved properties		$	86,327
	Proved properties		26,756
	Total assets acquired		$	113,083
	Bargain purchase gain		$	27,670
WEHLU Purchase Agreement	'
Business Acquisition [Line Items]	'
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	'
	The following table summarizes the estimated fair value of the assets acquired in connection with the WEHLU Acquisition (in thousands):
	Consideration:
	Cash consideration		$	177,778
	Estimated Fair Value of Assets Acquired:
	Unproved properties		$	13,026
	Proved properties		164,752
	Total assets acquired		$	177,778
Business Acquisition, Pro Forma Information	'
	The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Chesapeake and WEHLU Acquisitions are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes.
			Year Ended December 31, 2013
			(in thousands)
	Revenues		$	11,292
	Excess of revenues over direct operating expenses		$	7,591
	The following unaudited pro forma results for the years ended December 31, 2013 and 2012 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of each respective period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.
			For the Years Ended December 31,
			2013				2012
			(in thousands, except per share data)
			(Unaudited)
	Revenues		$	132,721			$	97,760
	Net Loss		$	(4,836	)		$	(175,809	)
	Loss per share:
	Basic		$	(0.08	)		$	(2.77	)
	Diluted		$	(0.08	)		$	(2.77	)

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Asset Retirement Obligations	'
	A summary of the activity related to the asset retirement obligation is as follows:
		For the years ended December 31,
		2013			2012			2011
		(in thousands)
	Asset retirement obligation, beginning of year	$	6,963		$	8,275		$	7,249
	Liabilities incurred during period	3,416			271			492
	Liabilities settled during period	(126		)	(297		)	—
	Accretion expense	468			388			534
	Revision in previous estimates and other	60			553			—
	Deletions related to property disposals	(4,718		)	$	(2,227	)	—
	Asset retirement obligation, end of year	$	6,063		$	6,963		$	8,275

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements, Recurring and Nonrecurring	'
	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012:
		Fair value as of December 31, 2013
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	32,393		$	—		$	—		$	32,393
	Commodity derivative contracts	—			—			7,545			7,545
	Liabilities:
	Commodity derivative contracts	—			—			(3,781		)	(3,781		)
	Total	$	32,393		$	—		$	3,764		$	36,157
		Fair value as of December 31, 2012
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	8,901		$	—		$	—		$	8,901
	Restricted cash	—			—			—			—
	Commodity derivative contracts	—			—			9,168			9,168
	Liabilities:
	Commodity derivative contracts	—			—			(2,703		)	(2,703		)
	Total	$	8,901		$	—		$	6,465		$	15,366
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation	'
	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2013 and 2012. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2013 and 2012.
		For the years ended December 31,
		2013			2012
		(in thousands)
	Balance at beginning of period	$	6,465		$	15,873
	Total gains (losses):
	included in earnings	(4,752		)	7,236
	Purchases	9,772			—
	Issuances	(2,308		)	—
	Settlements (1)	(5,413		)	(16,644		)
	Balance at end of period	$	3,764		$	6,465
	The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2013 and 2012	$	(9,967	)	$	(5,566	)
	_________________________________
	-1	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations

Derivative_Instruments_And_Hed1

Derivative Instruments And Hedging Activity (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative [Line Items]	'
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location	'
	The following table provides information regarding the deferred put premium liabilities for the periods indicated:
		For the Years Ended December 31,
		2013				2012
		(in thousands)
	Current commodity derivative premium put payable	$	145			$	—
	Long-term commodity derivative premium payable	7,000				—
	Total unamortized put premium liabilities	$	7,145			$	—
Schedule of Future Amortization of Deferred Put Premium Liabilities	'
	The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2013:
		Amortization
		(in thousands)
	September to December 2014	$	145
	January to December 2015	2,298
	January to December 2016	2,408
	January to December 2017	1,460
	January to August 2018	834
	Total unamortized put premium liabilities	$	7,145
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	'
	The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments:
		Fair Values of Derivative Instruments
		Derivative Assets (Liabilities)
				Fair Value
				December 31,
		Balance Sheet Location		2013				2012
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	Current assets		$	—			$	7,799
	Commodity derivative contracts	Other assets		7,545				1,369
	Commodity derivative contracts	Current liabilities		(3,403		)		(1,399		)
	Commodity derivative contracts	Long-term liabilities		(378		)		(1,304		)
	Total derivatives not designated as hedging instruments			$	3,764			$	6,465
		Amount of Gain (Loss) Recognized in Income on Derivatives
				Amount of Gain (Loss)
				Recognized in Income on
				Derivatives For the Years Ended December 31,
		Location of Gain (Loss) Recognized in		2013				2012				2011
		Income on Derivatives
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	(Loss) gain on commodity derivatives contracts		$	(4,752	)		$	7,422			$	12,204
	Commodity derivative contracts	Interest expense		—				(186		)		(136		)
	Total			$	(4,752	)		$	7,236			$	12,068
Natural Gas	'
Derivative [Line Items]	'
Schedule of Notional Amounts of Outstanding Derivative Positions	'
	As of December 31, 2013, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume			Volume			Price
					(in MMBtu's)
	2014		Fixed price swap		11,136			4,064,500			$	4.06			$	—	$	—	$	—
	2014		Fixed price swap		2,000			730,000			3.72				—		—		—
	2014		Fixed price swap		2,000			730,000			3.98				—		—		—
	2014		Fixed price swap		2,000			730,000			4.07				—		—		—
	2014		Short calls		2,500			912,500			—				—		—		4.59
	2014		Costless collar		3,000			1,095,000			—				4		—		4.36
	2014		Costless collar		5,000			1,825,000			—				4		—		4.55
	2014		Costless collar		2,500			912,500			—				4		—		4.71
	2014 (1)		Short puts		10,500			966,000			—				—		3		—
	2015		Fixed price swap		400			146,000			4				—		—		—
	2015		Fixed price swap		2,500			912,500			4.06				—		—		—
	2015		Protective spread		2,600			949,000			4				—		3.25		—
	2015		Costless three-way collar		2,000			760,000			—				4		3.25		4.58
	2016		Protective spread		2,000			732,000			4.11				—		3.25		—
	2016		Costless three-way collar		2,000			732,000			—				4		3.25		4.58
	_______________________________
	-1	For the period October to December 2014.
Crude Oil	'
Derivative [Line Items]	'
Schedule of Notional Amounts of Outstanding Derivative Positions	'
	As of December 31, 2013, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume (1)			Volume			Price
					(in Bbls)
	2014 (2)		Fixed price swap		300			54,300			$	98.05			$	—	$	—	$	—
	2014 (2)		Fixed price swap		550			99,550			95.15				—		—		—
	2014 (2)		Fixed price swap		900			162,900			93.21						—		—
	2014 (3)		Fixed price swap		750			138,000			90.35				—		—		—
	2014 (3)		Fixed price swap		200			36,800			93				—		—		—
	2014 (3)		Fixed price swap		350			64,400			91.55				—		—		—
	2014		Fixed price swap		500			182,500			91.1				—		—		—
	2014		Fixed price swap		270			98,500			90.77				—		—		—
	2014		Costless collar		200			73,000			—				98		—		98
	2014 (4)		Put spread		200			24,400			—				93		73		—
	2015		Costless three-way collar		400			146,000			—				85		70		96.5
	2015		Costless three-way collar		345			126,100			—				85		65		97.8
	2015 (5)		Costless three-way collar		150			27,150			—				85		65		96.25
	2015 (6)		Costless three-way collar		50			9,200			—				85		65		96.25
	2015 (5)		Put spread		700			126,700			—				90		70		—
	2015		Put spread		250			91,250			—				89		69		—
	2015 (6)		Put spread		600			110,400			—				87		67		—
	2016		Costless three-way collar		275			100,600			—				85		65		95.1
	2016		Costless three-way collar		330			120,780			—				80		65		97.35
	2016		Put spread		550			201,300			—				85		65		—
	2016		Put spread		300			109,800			—				85.5		65.5		—
	2017		Costless three-way collar		280			102,200			—				80		65		97.25
	2017		Costless three-way collar		242			88,150			—				80		60		98.7
	2017		Put spread		500			182,500			—				82		62		—
	2018 (7)		Put spread		425			103,275			—				80		60		—
	_______________________________
	-1	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
	-2	For the period January to June 2014.
	-3	For the period July to December 2014.
	-4	For the period September to December 2014.
	-5	For the period January to June 2015.
	-6	For the period July to December 2015.
	-7	For the period January to August 2018.

Capital_Stock_Tables

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Schedule of Issuances And Forfeitures Of Common Shares	'
	The following table provides information regarding the issuances and forfeitures of Parent’s common stock pursuant to Parent’s 2006 Long-Term Stock Incentive Plan for the periods indicated:
		For the Years Ended December 31,
		2013		2012
	Other stock issuances:
	Shares of restricted common stock granted	2,288,179		1,916,981
	Shares of restricted common stock vested	762,682		505,203
	Stock options exercised	10,000		3,000
	Shares of restricted common stock surrendered upon vesting/exercise (1)	224,500		141,458
	Shares of restricted common stock forfeited	512,862		74,463
	__________________
	-1	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period.
Schedule of Auction Market Preferred Securities by Stock Series	'
	Following a change in control, Gastar USA will have the option to redeem the Series A Preferred Stock, in whole but not in part, within 90 days after the date on which the change in control occurs, for cash at the following prices per share, plus accrued and unpaid dividends (whether or not declared), up to the redemption date:
	Redemption Date	Redemption
		Price
	Prior to June 23, 2014	$	25.25
	On or after June 23, 2014	$	25

Equity_Compensation_Plans_Tabl

Equity Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable	'
	The following tables summarize certain information related to outstanding stock options under the 2006 Plan as of and for the year ended December 31, 2013:
		Shares			Weighted Average			Weighted Average		Aggregate
					Exercise Price			Remaining		Intrinsic Value
					per Share			Contractual Term		(in thousands)
								(in years)
	Outstanding at December 31, 2012	959,100			$	11.31
	Granted	—			—
	Exercised	(10,000	)		2.6
	Canceled/Expired	—			—
	Forfeited	(75,000	)		8.18
	Outstanding at December 31, 2013	874,100			$	11.68
	Options vested and exercisable at December 31, 2013	864,100			$	11.76		3.17		$	739
Schedule of Nonvested Share Activity	'
		Shares			Weighted Average			Weighted Average				Weighted Average	Aggregate
					Fair Value			Exercise Price				Remaining	Intrinsic Value
					per Share			per Share				Contractual Term	(in thousands)
												(in years)
	Outstanding non-vested options at December 31, 2012	80,725			$	2.07
	Granted	—			—
	Vested	(50,725	)		1.73
	Forfeited	(20,000	)		2.58
	Outstanding non-vested options at December 31, 2013	10,000			$	2.74		$	4.27			0.04	$	27
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	'
	The following table summarizes information related to restricted shares at December 31, 2013:
		Shares			Weighted  Average			Weighted Average		Aggregate
					Fair Value			Remaining		Intrinsic Value (in thousands)
					per Share			Contractual Term
								(in years)
	Outstanding non-vested restricted shares at December 31, 2012	2,760,446			$	2.75
	Granted	2,288,179			1.3
	Vested	(762,682	)		3.57
	Forfeited	(512,862	)		1.87
	Outstanding non-vested restricted shares at December 31, 2013	3,773,081			$	1.82		8.68		$	26,110
Schedule of Share-based Compensation, Stock Options, Activity	'
	The table below provides a summary of PBUs as of the date indicated:
			PBUs			Fair Value per Unit
	Unvested PBUs at December 31, 2012		—			$	—
	Granted		1,192,889			1.56
	Vested		—			—
	Forfeited		(127,155	)		—
	Unvested PBUs at December 31, 2013		1,065,734			$	1.56
Schedule of Unrecognized Compensation Cost, Nonvested Awards	'
	As of December 31, 2013, the Company had approximately $2.7 million of total unrecognized compensation cost related to unvested stock options, restricted shares and PBUs, which is expected to be amortized over the following periods:
		Amount
		(in thousands)
	2014	$	2,028
	2015	594
	2016	66
	Total	$	2,688
Stock options	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	'
	The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated:
		For the Years Ended December 31,
		2013				2012			2011
		(in thousands, except per share data)
	Weighted average grant date fair value per stock option granted	$	—			$	—		$	—
	Intrinsic value of stock options exercised (1)	$	19			$	2		$	18
	Grant date fair value of stock options vested	$	88			$	117		$	282
	_______________
	-1	Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.
Unvested restricted shares	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	'
	The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated:
		For the Years Ended December 31,
		2013				2012			2011
		(in thousands, except per share data)
	Weighted average grant date fair value per restricted share	$	1.3			$	2.09		$	4.15
	Total fair value of restricted shares vested	$	2,725			$	2,492		$	2,436

Interest_Expense_Tables

Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2013
Interest Expense [Abstract]	'
Schedule of Components of Interest Expense	'
	The following tables summarize the components of the Company's interest expense for the periods indicated:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Interest expense:
	Cash and accrued	$	14,130		$	1,992		$	682
	Amortization of deferred financing costs (1)(2)	2,322			224			249
	Capitalized interest	(3,284		)	(1,946		)	(818		)
	Total interest expense	$	13,168		$	270		$	113
	_______________________________
	-1	The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. See Note 4, “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.”
	-2	The year ended December 31, 2013 includes $716,000 of debt discount accretion related to the Notes.
	The following tables summarize the components of Gastar USA's interest expense for the periods indicated:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Interest expense:
	Cash and accrued	$	13,978		$	1,993		$	681
	Amortization of deferred financing costs and debt discount (1)(2)	2,322			224			248
	Capitalized interest	(3,284		)	(1,946		)	(817		)
	Total interest expense	$	13,016		$	271		$	112
	_______________________________
	-1	The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. See Note 4, “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.”
	-2	The year ended December 31, 2013 includes $716,000 of debt discount accretion related to the Notes.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Contingency [Line Items]	'
Schedule of Income before Income Tax, Domestic and Foreign	'
	The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated:
		For the Year Ended December 31,
		2013			2012			2011
		(in thousands)
	United States	$	51,276		$	(152,322	)	$	285
	Foreign	(1,934		)	(1,469		)	(1,025		)
	Total income (loss) before income taxes	$	49,342		$	(153,791	)	$	(740	)
Schedule of Components of Income Tax Expense (Benefit)	'
	The Company’s income tax expense (benefit) consists of the following:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Current:
	Federal	$	—		$	—		$	—
	State	—			—			—
	Foreign	—			—			—
	Provision for income taxes	$	—		$	—		$	—
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Deferred:
	Federal	$	(15,299	)	$	—		$	—
	State	(743		)	—			—
	Foreign	—			—			—
	Income tax expense (benefit)	$	(16,042	)	$	—		$	—
Schedule of Effective Income Tax Rate Reconciliation	'
	The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Expected income tax provision (benefit) at statutory rate	$	11,655		$	(53,827	)	$	(259	)
	State tax, tax effected	96			(2,562		)	—
	Non-deductible stock-based compensation expense	605			560			441
	Tax effect of Canadian tax rate differences	193			(125		)	(103		)
	Loss of Canadian tax attributes due to migration from Canada	19,825			—			—
	Gain on acquisition of assets at fair value	(9,685		)	—			—
	Non-deductible costs of migration from Canada to U.S.	95			—			—
	Other	(49		)	15			10
	Other changes in valuation allowance	(38,777		)	55,939			(89		)
	Actual income tax provision	$	(16,042	)	$	—		$	—
Schedule Of Undeducted Tax Pool	'
	The following tables present the Canadian tax attributes forfeited and the release of the Canadian valuation allowance resulting from the Migration.
		As of December 31,
		2013			2012
		(in thousands)
	Canadian and foreign exploration and development expense	$	—		$	2,597
	Undeducted share issuance costs	$	—		$	1,239
	Undeducted non-capital and capital loss carry forwards	$	—		$	73,522
US	'
Income Tax Contingency [Line Items]	'
Schedule of Deferred Tax Assets and Liabilities	'
	The components of the Company’s U.S. deferred taxes are as follows:
		As of December 31,
		2013			2012
		(in thousands)
	Deferred tax asset (liability):
	Capital assets	$	(70,955	)	$	(22,668	)
	Net operating loss carry forwards	122,675			93,339
	Foreign tax credit carry forwards	50,681			50,681
	Valuation allowance	(102,401		)	(121,352		)
	Net deferred tax asset	$	—		$	—
Canada	'
Income Tax Contingency [Line Items]	'
Schedule of Deferred Tax Assets and Liabilities	'
	The components of Parent’s Canadian deferred tax assets are as follows:
		As of December 31,
		2013			2012
		(in thousands)
	Deferred tax asset:
	Capital assets	$	—		$	649
	Share issuance costs	—			310
	Tax loss carry forwards	—			18,381
	Valuation allowance	—			(19,340		)
	Net deferred tax asset	$	—		$	—

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share, Basic and Diluted	'
		For the Years Ended December 31,
		2013		2012			2011
		(in thousands, except per share and share data)
	Net loss attributable to Gastar Exploration, Inc.	$	39,964	$	(160,868	)	$	(1,764	)
	Weighted average shares of common stock outstanding - basic	60,220,115		63,538,362			63,003,579
	Incremental shares from unvested restricted shares	2,869,490		—			—
	Incremental shares from outstanding stock options	26,095		—			—
	Incremental shares from outstanding PBUs	502,701		—			—
	Weighted average shares of common stock outstanding - diluted	63,618,401		63,538,362			63,003,579
	Net loss per share of common stock attributable to Gastar Exploration, Inc. Common Stockholders:
	Basic	$	0.66	$	(2.53	)	$	(0.03	)
	Diluted	$	0.63	$	(2.53	)	$	(0.03	)
	Shares of common stock excluded from denominator as anti-dilutive:
	Unvested restricted shares	3,505		1,831,435			641,606
	Stock options	—		936,967			810,235
	Total	3,505		2,768,402			1,451,841

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of future minimum annual rental commitments	'
	As of December 31, 2013, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows:
	2014	$	681
	2015	602
	2016	453
	2017	142
	2018	117
		$	1,995

Concentration_of_Risk_and_Sign1

Concentration of Risk and Significant Customers (Tables)	12 Months Ended
	Dec. 31, 2013
Risks and Uncertainties [Abstract]	'
Schedules of Concentration of Risk, by Risk Factor	'
	The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated:
			For the Years Ended December 31,
			2013		2012		2011
	Marcellus Shale and Other Appalachia		65	%	72	%	15	%
	Mid-Continent		26	%	—	%	—	%
	Hilltop Area, East Texas (1)		9	%	27	%	79	%
	Powder River Basin (2)		—	%	1	%	6	%
	__________________
	-1	The Company's working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013.
	-2	The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012.
	The following table provides information regarding our significant customers and the percentages of oil, condensate, natural gas and NGLs revenues, excluding hedge impact, which they represented for the periods indicated:
			For the Years Ended December 31,
			2013		2012		2011
	SEI		56	%	47	%	8	%
	Sunoco		16	%	—	%	—	%
	Clearfield Appalachian		8	%	14	%	—	%
	ETC		8	%	24	%	69	%
	Plains Marketing LP		1	%	2	%	10	%

Statement_Of_Cash_Flows_Supple1

Statement Of Cash Flows - Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2013
Other Significant Noncash Transactions [Line Items]	'
Statement Of Cash Flows Supplemental Information	'
	The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:
		For the Years Ended December 31,
		2013			2012			2011
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	7,341		$	39		$	—
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued drilling costs	$	582		$	4,666		$	4,600
	Capital expenditures excluded from accounts receivable	(4,077		)	(929		)	—
	Capital expenditures excluded from prepaid expenses	—			—			48
	Asset retirement obligation included in natural gas and oil properties	(1,302		)	1,164			492
	Asset retirement obligation sold/assigned to operator	(4,354		)	(2,227		)	—
	Application of advances to operators	19,755			7,441			6,529
	Other	47			(36		)	—
Gastar Exploration USA	'
Other Significant Noncash Transactions [Line Items]	'
Statement Of Cash Flows Supplemental Information	'
	The following is a summary of Gastar USA's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:
		For the Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	7,341		$	39		$	—
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued costs	$	582		$	4,666		$	4,600
	Capital expenditures excluded from accounts receivable	(4,077		)	(929		)	—
	Capital expenditures excluded from prepaid expenses	—			—			48
	Asset retirement obligation included in natural gas and oil properties	(1,302		)	1,164			492
	Asset retirement obligation assigned to operator	(4,354		)	(2,227		)	—
	Application of advances to operators	19,755			7,441			6,529
	Due to (from) Parent - transfer to equity, net	15,495			5,295			2,612
	Other	47			(36		)	—

Quarterly_Consolidated_Financi1

Quarterly Consolidated Financial Data - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule Of Quarterly Financial Information [Line Items]	'
Schedule Of Quarterly Financial Information	'
	The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2013 and 2012:
		2013
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	11,264		$	30,926		$	18,840		$	26,725
	Income (loss) from operations	(1,849		)	13,809			1,626			5,178
	Income (loss) before provision for income taxes (1)	(2,456		)	53,970			(1,808		)	(16,406		)
	Net income (loss)	(2,456		)	53,970			(1,808		)	(364		)
	Dividend on preferred stock attributable to non-controlling interest	2,130			2,134			2,134			2,980
	Net income (loss) attributable to Gastar Exploration, Inc.	(4,586		)	51,836			(3,942		)	(3,344		)
	Net income (loss) per share of common stock attributable to Gastar Exploration, Inc. Common Stockholders:
	Basic	$	(0.07	)	$	0.83		$	(0.07	)	$	(0.06	)
	Diluted	$	(0.07	)	$	0.81		$	(0.07	)	$	(0.06	)
	Weighted average shares of common stock outstanding:
	Basic	63,864,527			62,398,472			57,359,357			57,433,550
	Diluted	63,864,527			63,813,423			57,359,357			57,433,550
	_______________
	-1	Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.
		2012
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	9,154		$	13,921		$	9,443		$	17,422
	Income (loss) from operations (1)	(5,052		)	(72,237		)	(81,443		)	5,245
	Income (loss) before provision for income taxes	(5,074		)	(72,308		)	(81,473		)	5,064
	Net income (loss)	(5,074		)	(72,308		)	(81,473		)	5,064
	Dividend on preferred stock attributable to non-controlling interest	1,236			1,727			1,984			2,130
	Net income (loss) attributable to Gastar Exploration, Inc	(6,310		)	(74,035		)	(83,457		)	2,934
	Net income (loss) per share of common stock attributable to Gastar Exploration, Inc. Common Stockholders:
	Basic	$	(0.10	)	$	(1.17	)	$	(1.31	)	$	0.05
	Diluted	$	(0.10	)	$	(1.17	)	$	(1.31	)	$	0.05
	Weighted average shares of common stock outstanding:
	Basic	63,336,437			63,541,739			63,601,645			63,669,744
	Diluted	63,336,437			63,541,739			63,601,645			63,678,597
	_______________
	-1	Loss from operations for the second and third quarters of 2012 include a quarterly ceiling test impairment charge of $72.7 million and $78.1 million, respectively.
Gastar Exploration USA	'
Schedule Of Quarterly Financial Information [Line Items]	'
Schedule Of Quarterly Financial Information	'
	The following tables summarize Gastar USA’s results of operations by quarter for the years ended December 31, 2013 and 2012:
		2013
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	11,264		$	30,926		$	18,840		$	26,725
	Income (loss) from operations (1)	(1,628		)	14,157			2,086			5,957
	Income (loss) before provision for income taxes	(2,231		)	54,312			(1,363		)	(15,483		)
	Net income (loss)	(2,231		)	54,312			(1,363		)	559
	Dividends on preferred stock	2,130			2,134			2,134			2,980
	Net income (loss) attributable to common stockholder	(4,361		)	52,178			(3,497		)	(2,421		)
	_______________
	-1	Income before provision for income taxes for the second quarter of 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.
		2012
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	9,154		$	13,921		$	9,443		$	17,422
	Income (loss) from operations (1)	(4,662		)	(71,980		)	(80,973		)	5,566
	Income (loss) before provision for income taxes	(4,686		)	(72,011		)	(81,007		)	5,382
	Net income (loss)	(4,686		)	(72,011		)	(81,007		)	5,382
	Dividend on preferred stock	1,236			1,727			1,984			2,130
	Net income (loss) attributable to common stockholder	(5,922		)	(73,738		)	(82,991		)	3,252
	_______________
	-1	Loss from operations for the second and third quarters of 2012 include a quarterly ceiling test impairment charge of $72.7 million and $78.1 million, respectively.

Supplemental_Oil_and_Gas_Discl1

Supplemental Oil and Gas Disclosures - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2013
Reserve Quantities [Line Items]	'
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	'
	The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities for the periods indicated:
		As of December 31,
		2013				2012				2011
		(in thousands)
	Proved properties:
	United States	$	935,773			$	671,193			$	514,357
	Total proved properties	935,773				671,193				514,357
	Unproved properties:
	United States	96,220				67,892				78,302
	Total unproved properties	96,220				67,892				78,302
	Total natural gas and oil properties	1,031,993				739,085				592,659
	Less:
	Impairment of proved natural gas and oil properties
	United States	(337,939		)		(337,939		)		(187,152		)
	Accumulated depreciation, depletion and amortization	(177,790		)		(145,631		)		(120,436		)
	Net capitalized costs	$	516,264			$	255,515			$	285,071
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	'
	The following table sets forth costs incurred related to the Company’s oil and natural gas activities in the U.S. for the periods indicated:
			For the years ended December 31,
			2013				2012				2011
			(in thousands)
	Property acquisition
	Proved (1)		$	189,594			$	—			$	—
	Unproved (2)		71,472				25,676				19,552
	Exploration		36,893				10,041				47,668
	Development		53,058				111,878				18,167
	Total costs incurred		$	351,017			$	147,595			$	85,387
	_______________
	-1	The 2013 property acquisition costs excludes a downward adjustment of $2.6 million for fair value of acquisition.
	-2	The 2013 property acquisition costs excludes $46.3 million of adjustment for fair value of acquisition.
Results of Operations for Oil and Gas Producing Activities Disclosure	'
	The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated:
		For the Year Ended December 31,
		2013				2012				2011
		(in thousands, except per Mcfe data)
	Oil, condensate, natural gas and NGLs sales, including commodity derivatives	$	87,755			$	49,940			$	40,235
	Production expenses	(18,113		)		(13,408		)		(13,751		)
	Impairment of oil and natural gas properties	—				(150,787		)		—
	Depreciation, depletion and amortization	(32,158		)		(25,195		)		(14,989		)
	Results of producing activities	$	37,484			$	(139,450	)		$	11,495
	Depreciation, depletion and amortization per Mcfe	$	1.66			$	1.9			$	1.95
	Depreciation, depletion and amortization per MBoe	$	9.94			$	11.41			$	11.7
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	'
	For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations:
		For the Years Ended December 31,
		2013				2012				2011
	Natural gas, per MMBtu
	Henry Hub	$	3.67			$	2.76			$	4.12
	Oil, per barrel:
	WTI posting	$	—			$	91.21			$	75.96
	WTI spot	$	96.78			$	94.71			$	—
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	'
	The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2013, 2012 and 2011:
	Change in Proved Reserves	Natural  Gas			NGLs			Condensate and Oil			MMcfe (1)		MBoe (4) Equivalents (5)
		(MMcf) (1)			(MBbl) (2)			(MBbl) (2)			Equivalents  (3)
	Proved reserves as of December 31, 2010	49,892			—			61			50,260		8,376
	2011 Activity:
	Extensions and discoveries	56,364			2,767			1,945			84,634		14,106
	Revisions of previous estimates (6)	(7,286	)		11			(45	)		(7,494	)	(1,248	)
	Production	(7,318	)		(21	)		(40	)		(7,684	)	(1,281	)
	Proved reserves as of December 31, 2011	91,652			2,757			1,921			119,716		19,953
	2012 Activity:
	Extensions and discoveries (7)	57,835			2,783			2,439			89,169		14,861
	Revisions of previous estimates	(6,518	)		(348	)		(796	)		(13,375	)	(2,230	)
	Production	(10,564	)		(270	)		(177	)		(13,247	)	(2,208	)
	Purchases in place	—			—			7			41		7
	Sales in place	(1,395	)		—			—			(1,395	)	(231	)
	Proved reserves as of December 31, 2012	131,010			4,922			3,394			180,909		30,152
	2013 Activity:
	Extensions and discoveries (8)	52,750			2,306			4,385			92,897		15,483
	Revisions of previous estimates	8,114			714			(337	)		10,375		1,729
	Production	(13,366	)		(494	)		(515	)		(19,417	)	(3,237	)
	Purchases in place	26,961			2,350			7,796			87,832		14,639
	Sales in place	(24,759	)		—			(5	)		(24,791	)	(4,132	)
	Proved reserves as of December 31, 2013	180,710			9,798			14,718			327,805		54,634
	_______________
	-1	Million cubic feet or million cubic feet equivalent, as applicable
	-2	Thousand barrels
	-3	Oil, condensate and NGLs volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one barrel of oil, condensate or NGLs.
	-4	Thousand barrels of oil, condensate or NGLs equivalent.
	-5	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
	-6	The 2011 downward revision of previous estimates of natural gas is primarily attributed to the decision to forgo an East Texas PUD location due to low natural gas prices which would have resulted in drilling beyond the five-year maximum carry period.
	-7	The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery.
	-8	74% of the 2013 extensions and discoveries resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
	Proved Developed and Undeveloped Reserves	Natural Gas			NGLs			Condensate and Oil			MMcfe (1)		MBoe (4) Equivalents (5)
		(MMcf) (1)			(MBbl) (2)			(MBbl) (2)			Equivalents (3)
	31-Dec-11
	Proved developed reserves	65,061			1,339			904			78,518		13,087
	Proved undeveloped reserves	26,591			1,418			1,017			41,198		6,867
	Total	91,652			2,757			1,921			119,716		19,954
	31-Dec-12
	Proved developed reserves	95,602			3,215.80			1,959			126,653		21,109
	Proved undeveloped reserves	35,408			1,706			1,435			54,256		9,042
	Total	131,010			4,922			3,394			180,909		30,151
	31-Dec-13
	Proved developed reserves	114,195			6,025			5,834			185,349		30,892
	Proved undeveloped reserves	66,515			3,773			8,884			142,456		23,742
	Total	180,710			9,798			14,718			327,805		54,634
	_______________
	-1	Million cubic feet or million cubic feet equivalent, as applicable
	-2	Thousand barrels
	-3	Oil, condensate and NGLs volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one barrel of oil, condensate or NGLs.
	-4	Thousand barrels of oil, condensate or NGLs equivalent.
	-5	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	'
	The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is presented below:
		United States
		(in thousands)
	December 31, 2011:
	Future cash inflows	$	584,067
	Future production costs	(101,938		)
	Future development costs	(57,843		)
	Future income taxes	(33,732		)
	Future net cash flows	390,554
	10% annual discount for estimated timing of cash flows	(177,771		)
	Standardized measure of discounted future cash flows	$	212,783
	December 31, 2012:
	Future cash inflows	$	672,142
	Future production costs	(167,864		)
	Future development costs	(83,697		)
	Future income taxes (1)	—
	Future net cash flows	420,581
	10% annual discount for estimated timing of cash flows	(213,772		)
	Standardized measure of discounted future cash flows	$	206,809
	December 31, 2013:
	Future cash inflows	$	2,103,023
	Future production costs	(588,568		)
	Future development costs	(296,666		)
	Future income taxes	(76,701		)
	Future net cash flows	1,141,088
	10% annual discount for estimated timing of cash flows	(625,259		)
	Standardized measure of discounted future cash flows	$	515,829
	_______________
	-1	No future taxes payable has been included in the determination of discounted future net cash flows for 2012 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	'
	The principal sources of changes in the standardized measure of future net cash flows are as follows:
		United States
		(in thousands)
	December 31, 2010	$	67,282
	Extensions and discoveries, less related costs	180,539
	Sale of natural gas and oil, net of production costs	(24,148		)
	Revisions of previous quantity estimates	(9,323		)
	Net change in income tax	(4,334		)
	Net change in prices and production costs	12,394
	Accretion of discount	5,011
	Development costs incurred	1,482
	Net change in estimated future development costs	4,541
	Change in production rates (timing) and other	(20,661		)
	December 31, 2011	$	212,783
	Extensions and discoveries, less related costs	112,390
	Sale of natural gas and oil, net of production costs	(29,110		)
	Purchases of reserves in place	64
	Sales of reserves in place	(216		)
	Revisions of previous quantity estimates	(30,959		)
	Net change in income tax	4,334
	Net change in prices and production costs	(98,589		)
	Accretion of discount	1,152
	Development costs incurred	19,702
	Net change in estimated future development costs	2,518
	Change in production rates (timing) and other	12,740
	December 31, 2012	$	206,809
	Extensions and discoveries, less related costs	196,448
	Sale of natural gas and oil, net of production costs	(74,394		)
	Purchases of reserves in place	247,208
	Sales of reserves in place	(9,063		)
	Revisions of previous quantity estimates	6,191
	Net change in income tax	(76,701		)
	Net change in prices and production costs	79,820
	Accretion of discount	1,211
	Development costs incurred	23,567
	Net change in estimated future development costs	(97,461		)
	Change in production rates (timing) and other	12,194
	December 31, 2013	$	515,829
Key Natural Gas and Oil Prices	'
Reserve Quantities [Line Items]	'
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	'
	The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves:
		As of December 31,
		2013				2012
	Natural gas (per MMBtu):
	Henry Hub	$	3.67			$	2.76
	Oil (per Bbl):
	WTI posting	$	—			$	91.21
	WTI spot	$	96.78			94.71

Recovered_Sheet2

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Line Items]	'	'	'	'
Cash and cash equivalents	$32,393	$8,901	$10,647	$7,439
Capitalized interest	($3,284)	($1,946)	($818)	'
Canada	'	'	'	'
Accounting Policies [Line Items]	'	'	'	'
Number of gas wells	2	'	'	'
Minimum | Furniture and equipment	'	'	'	'
Accounting Policies [Line Items]	'	'	'	'
Estimated useful lives	'3 years	'	'	'
Maximum | Furniture and equipment	'	'	'	'
Accounting Policies [Line Items]	'	'	'	'
Estimated useful lives	'7 years	'	'	'

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Schedule of Allowance for Doubtful Accounts) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Allowance for Doubtful Accounts Receivable [Roll Forward]	'	'	'
Allowance for doubtful accounts, beginning of year	$546	$551	$571
Expense	0	0	0
Reductions/write-offs	-39	-5	-20
Allowance for doubtful accounts, end of year	$507	$546	$551

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Schedule of Deferred Financing Costs) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'	'
Deferred charges	$3,269	$2,525
Accumulated amortization	-319	-1,689
Deferred charges, net	$2,950	$836

Property_Plant_And_Equipment_N

Property, Plant And Equipment (Narrative) (Details) (USD $)

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 30, 2010

Dec. 31, 2013

Dec. 31, 2012

Nov. 02, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jun. 27, 2013

Jul. 02, 2013

Jun. 07, 2013

Dec. 31, 2013

Mar. 28, 2013

Jul. 04, 2013

Nov. 15, 2013

Sep. 04, 2013

Apr. 19, 2013

Jul. 02, 2013

Jun. 07, 2013

well

Atinum Joint Venture

Atinum Joint Venture

Atinum Joint Venture

Atinum Joint Venture

Maximum

Maximum

Minimum

East Texas

East Texas

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

well

well

well

acre

Atinum Joint Venture

Atinum Joint Venture

Atinum Joint Venture

Hunton Joint Venture

Hunton Joint Venture

Chesapeake Assets

Chesapeake Assets

Chesapeake Assets

Oklahoma Oil and Gas Leasehold Interests

WEHLU Purchase Agreement

WEHLU Purchase Agreement

East Texas

Hunton Divestiture

General and Administrative Expense

well

well

well

well

acre

acre

acre

acre

acre

acre

Chesapeake Assets

well

Property, Plant and Equipment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset retirement obligation

'

$3,400,000

$4,800,000

$5,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reclassification of unproved properties to proved properties

'

'

'

'

'

'

'

'

'

'

'

20,500,000

24,400,000

'

'

'

'

'

'

'

'

'

'

'

Net acres

'

'

'

'

'

'

'

34,200

'

'

'

'

'

'

12,800

'

'

157,000

1,850

'

24,000

16,300

76,000

'

Productive conventional wells (wells)

'

'

'

'

'

'

'

16

'

'

'

'

'

'

'

'

'

206

'

'

'

'

'

'

Cash consideration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69,434,000

'

'

'

177,778,000

'

'

'

'

Transaction and integration costs

'

'

'

'

'

'

'

'

'

'

'

'

'

133,000

'

'

'

'

'

286,000

'

'

'

2,100,000

Fair market valuation amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

113,083,000

'

'

'

177,778,000

'

'

'

'

Gain on acquisition of assets at fair value

43,712,000

27,670,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

27,670,000

'

'

'

'

'

'

'

Acquisition of oil and natural gas properties

'

251,096,000

0

0

'

'

'

'

'

'

'

'

'

11,800,000

'

'

'

'

'

'

'

'

'

'

Net cash purchase price of divestiture

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

57,000,000

'

Working interest In wells (percentage)

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

98.30%

'

'

'

Net Revenue Interest in Wells

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.50%

'

'

'

Gross acres

'

'

'

'

'

'

'

37,600

'

'

'

'

'

'

'

'

'

'

'

'

'

31,800

'

'

Proceeds from sale of natural gas and oil properties

'

112,201,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

42,900,000

'

'

Initial interest in assets (percentage)

'

'

'

'

'

'

'

21.43%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non productive number of wells

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of Marcellus Shale assets

'

'

'

'

30,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash received from Atinum for drilling carrying costs

'

'

'

'

40,000,000

'

40,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Atinum ownership interest in Atinum Joint Venture Assets (percentage)

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of share of drilling completion and infrastructure costs carried (percentage)

'

'

'

'

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Joint interest share of drilling completion and infrastructure costs (percentage)

'

'

'

'

50.00%

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of development program

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum wells to be drilled (wells)

'

'

'

'

'

'

12

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Required exploratory wells drilled net productive to be drilled in current fiscal year (wells)

'

'

'

'

'

'

'

'

'

24

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Required exploratory wells drilled net productive to be drilled in next fiscal year (wells)

'

'

'

'

'

'

'

'

24

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amended required exploratory wells drilled net productive to be drilled in current fiscal year (wells)

'

'

'

'

'

'

'

'

'

'

20

'

'

'

'

'

'

'

'

'

'

'

'

'

Extended required exploratory wells drilled gross productive to be drilled in current fiscal year

'

'

'

'

'

29

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Extended required exploratory wells drilled net productive to be drilled in current fiscal year

'

'

'

'

'

13.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross operated wells drilled, completed and on production

'

'

'

'

'

57

38

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operated wells drilled, completed and on production

'

'

'

'

'

27

17.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total Reduction In Required Exploratory Wells Drilled Net Productive To Be Drilled In Current Fiscal Year

'

19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total Revised Required Exploratory Wells Drilled Net Productive To Be Drilled

'

57

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total Required Exploratory Wells Drilled Net Productive To Be Drilled

'

60

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of reimbursements for lease bonuses and third party lease costs up to 20 million (percentage)

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of lease operating expenses covered (percentage)

'

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$176,800,000

'

'

'

'

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule of Property Plant and Equipment) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'	'
Unproved properties	$96,220	$67,892	$78,302
Proved properties	935,773	671,193	514,357
Total oil and natural gas properties	1,031,993	739,085	'
Total property and equipment	1,034,684	741,010	'
Impairment of proved natural gas and oil properties	-337,939	-337,939	'
Accumulated depreciation, depletion and amortization	-179,232	-146,820	'
Total accumulated depreciation, depletion and amortization	-517,171	-484,759	'
Total property, plant and equipment, net	517,513	256,251	'
Total oil and natural gas properties	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Unproved properties	96,220	67,892	'
Proved properties	935,773	671,193	'
Total oil and natural gas properties	1,031,993	739,085	'
Furniture and equipment	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Total property and equipment	$2,691	$1,925	'

Property_Plant_And_Equipment_S1

Property, Plant And Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Unproved properties, excluded from amortization:	'	'
Drilling in progress costs	$4,774	$1,902
Acreage acquisition costs	86,097	62,395
Capitalized interest	5,349	3,595
Total unproved properties excluded from amortization	$96,220	$67,892

Property_Plant_And_Equipment_S2

Property, Plant And Equipment (Schedule of Relevant Assumptions Used In Ceiling Test Computations) (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

In Thousands, unless otherwise specified

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2012

Jun. 30, 2012

Sep. 30, 2011

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

Henry Hub natural gas price (per MMBtu)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

West Texas Intermediate oil price (per Bbl)

Average Sales Price and Production Costs Per Unit of Production [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Key natural gas and oil prices

'

'

'

'

'

'

'

'

'

3.67

[1]

3.61

[1]

3.44

[1]

2.95

[1]

2.76

[1]

2.83

[1]

3.15

[1]

3.73

[1]

4.12

[1]

4.16

[1]

4.21

[1]

4.1

[1]

96.78

[1]

91.69

[1]

88.13

[1]

89.17

[1]

91.21

[1]

91.48

[1]

92.17

[1]

94.65

[1]

92.71

[1]

91

[1]

86.6

[1]

80.04

[1]

Impairment of natural gas and oil properties

$0

$0

$78,054

$72,733

$0

$0

$0

$150,787

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Property_Plant_And_Equipment_S3

Property, Plant And Equipment (Schedule of Assets Acquired) (Details) (USD $)	3 Months Ended	12 Months Ended			0 Months Ended	12 Months Ended	0 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 07, 2013	Dec. 31, 2013	Nov. 15, 2013
					Chesapeake Assets	Chesapeake Assets	WEHLU Purchase Agreement
					Gastar Exploration USA	Gastar Exploration USA	Gastar Exploration USA
Business Acquisition [Line Items]	'	'	'	'	'	'	'
Cash consideration	'	'	'	'	$69,371	'	'
Deferred tax liability	'	'	'	'	16,042	'	'
Total purchase price plus liabilities assumed	'	'	'	'	85,413	'	'
Cash consideration	'	'	'	'	69,434	'	177,778
Unproved properties	'	'	'	'	86,327	'	13,026
Proved properties	'	'	'	'	26,756	'	164,752
Total assets acquired	'	'	'	'	113,083	'	177,778
Gain on acquisition of assets at fair value	$43,712	$27,670	$0	$0	'	$27,670	'

Property_Plant_And_Equipment_S4

Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) (WEHLU Purchase Agreement, Gastar Exploration USA, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
WEHLU Purchase Agreement | Gastar Exploration USA	'	'
Business Acquisition [Line Items]	'	'
Revenues	$132,721	$97,760
Net Loss	-4,836	-175,809
Loss per share, Basic	($0.08)	($2.77)
Loss per share, Diluted	($0.08)	($2.77)
Revenues	11,292	'
Excess of revenues over direct operating expenses	$7,591	'

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)

Dec. 31, 2013

Oct. 18, 2013

Oct. 17, 2013

Dec. 31, 2012

15-May-13

Dec. 31, 2013

Nov. 15, 2013

Oct. 18, 2013

Oct. 17, 2013

Dec. 31, 2013

Nov. 10, 2011

Oct. 28, 2009

Dec. 31, 2013

Mar. 06, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 09, 2013

Jun. 07, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 07, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Minimum

Minimum

Maximum

Federal Funds Rate

Prime Rate

LIBO Rate

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Minimum

Maximum

Federal Funds Rate

Prime Rate

Prime Rate

Eurodollar

Eurodollar

Prime Rate

LIBO Rate

Minimum

Maximum

Minimum

Maximum

Line of Credit Facility [Line Items]

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving credit facility borrowing base

'

'

'

'

'

'

'

'

'

'

'

$47,500,000

'

'

'

'

'

'

$100,000,000

$100,000,000

$50,000,000

'

'

'

'

'

'

'

$160,000,000

'

'

Federal funds rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'federal funds rate plus

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'

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'

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'

'

'

'

'

'

'prime rate

'LIBO rate

Applicable interest rate margin

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500.00%

1.00%

2.00%

2.00%

3.00%

'

'

'

Annual commitment fee (percentage)

'

'

'

'

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of stock foreign subsidiary pledged as collateral for credit facility (percentage)

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility covenant compliance Current Ratio

'

'

'

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'

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'

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'

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1

0.6

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

Line of credit facility covenant compliance indebtedness to EBITDA Ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

Line of credit facility covenant compliance EBITDA to Interest Expense Ratio on a four quarter rolling basis

'

'

'

'

'

'

'

'

'

2.5

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'

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'

'

'

'

2.5

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'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount

'

'

'

'

200,000,000

'

125,000,000

325,000,000

200,000,000

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate amount of cash dividends permitted to be paid to preferred stockholders

'

20,000,000

12,500,000

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

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Revolving Credit Facility, remaining borrowing capacity

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

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'

100,000,000

'

'

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'

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'

'

'

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'

'

Revolving Credit Facility amount outstanding

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

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0

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'

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'

'

'

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'

'

'

Percentage increase in adjusted consolidated net tangible assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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17.50%

'

'

'

'

'

'

'

'

'

'

'

'

Applicable interest rate margin minimum (percentage)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable interest rate margin maximum (percentage)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.00%

3.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of proved developed producing reserves hedged allowed under credit facility agreement (percentage)

'

'

'

'

'

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'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate

'

'

'

'

8.63%

8.63%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net proceeds received net of debt issuance costs

'

'

'

'

'

312,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption percentage of aggregate principal amount

'

'

'

'

101.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

Long-term debt

312,994,000

'

'

98,000,000

'

313,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized discounts

'

'

'

'

'

$12,000,000

'

'

'

'

'

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'

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Asset retirement obligation, beginning of year	$6,963	$8,275	$7,249
Liabilities incurred during period	3,416	271	492
Liabilities settled during period	-126	-297	0
Accretion of asset retirement obligation	468	388	534
Revision in previous estimates and other	60	553	0
Deletions related to property disposals	-4,718	-2,227	0
Asset retirement obligation, end of year	6,063	6,963	8,275
Asset retirement obligation	$633	$358	'

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
East Texas	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Reclassification of unproved properties to proved properties	$20.50	$24.40
Level 1	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Estimated fair value of long term debt	$324.60	'

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Assets [Abstract]	'	'
Assets, Commodity derivative contracts	$7,545	$9,168
Derivative Liabilities [Abstract]	'	'
Liabilities, Commodity derivative contracts	-3,781	-2,703
Total	36,157	15,366
Level 1	'	'
Derivative Assets [Abstract]	'	'
Assets, Commodity derivative contracts	0	0
Derivative Liabilities [Abstract]	'	'
Liabilities, Commodity derivative contracts	0	0
Total	32,393	8,901
Level 2	'	'
Derivative Assets [Abstract]	'	'
Assets, Commodity derivative contracts	0	0
Derivative Liabilities [Abstract]	'	'
Liabilities, Commodity derivative contracts	0	0
Total	0	0
Level 3	'	'
Derivative Assets [Abstract]	'	'
Assets, Commodity derivative contracts	7,545	9,168
Derivative Liabilities [Abstract]	'	'
Liabilities, Commodity derivative contracts	-3,781	-2,703
Total	3,764	6,465
Cash and cash equivalents	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	32,393	8,901
Cash and cash equivalents | Level 1	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	32,393	8,901
Cash and cash equivalents | Level 2	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	0	0
Cash and cash equivalents | Level 3	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	0	0
Restricted cash	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	'	0
Restricted cash | Level 1	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	'	0
Restricted cash | Level 2	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	'	0
Restricted cash | Level 3	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	'	$0

Fair_Value_Measurements_Net_Ch

Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) (Fair Value, Inputs, Level 3, Commodity, Fair Value, Measurements, Recurring, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Measurements, Recurring	'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'		'
Balance at beginning of period	'		'		$15,873
Total gains (losses):	'		'		'
included in earnings	-4,752		7,236		'
Purchases	9,772		0		'
Issuances	-2,308		0		'
Settlements	-5,413	[1]	-16,644	[1]	'
Balance at end of period	3,764		6,465		15,873
The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2013 and 2012	($9,967)		($5,566)		'
[1]	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations

Derivative_Instruments_And_Hed2

Derivative Instruments And Hedging Activity (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]	'	'	'
Amount of Gain/ (Loss) Recognized in Income on Derivatives	($4,752)	$7,236	$12,068
Unrealized hedge (gain) loss	-4,752	7,422	12,204
(Loss) gain on commodity derivatives contracts	'	'	'
Derivative [Line Items]	'	'	'
Amount of Gain/ (Loss) Recognized in Income on Derivatives	($4,752)	$7,422	$12,204

Derivative_Instruments_And_Hed3

Derivative Instruments And Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2013
	MMBTU
Natural Gas | 2014 | Short calls	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	912,500
Ceiling (Short) (Price per MMBtu)	4.59
Natural Gas | 2014 | Short puts	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	10,500	[1]
Total of Notional Volume (MMBtu's or Bbls)	966,000	[1]
Short Put (Price per MMBtu)	3	[1]
Natural Gas | 2015 | Protective spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,600
Total of Notional Volume (MMBtu's or Bbls)	949,000
Base Fixed Price (Price per MMbtu or Bbl)	4
Short Put (Price per MMBtu)	3.25
Natural Gas | 2015 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	760,000
Floor (Long) (Price per MMBtu)	4
Short Put (Price per MMBtu)	3.25
Ceiling (Short) (Price per MMBtu)	4.58
Natural Gas | 2016 | Protective spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	732,000
Base Fixed Price (Price per MMbtu or Bbl)	4.11
Short Put (Price per MMBtu)	3.25
Natural Gas | 2016 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	732,000
Floor (Long) (Price per MMBtu)	4
Short Put (Price per MMBtu)	3.25
Ceiling (Short) (Price per MMBtu)	4.58
Crude Oil | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	200	[2]
Total of Notional Volume (MMBtu's or Bbls)	73,000
Floor (Long) (Price per MMBtu)	98
Ceiling (Short) (Price per MMBtu)	98
Crude Oil | 2015 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	400	[2]
Total of Notional Volume (MMBtu's or Bbls)	146,000
Floor (Long) (Price per MMBtu)	85
Short Put (Price per MMBtu)	70
Ceiling (Short) (Price per MMBtu)	96.5
Crude Oil | 2016 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	275	[2]
Total of Notional Volume (MMBtu's or Bbls)	100,600
Floor (Long) (Price per MMBtu)	85
Short Put (Price per MMBtu)	65
Ceiling (Short) (Price per MMBtu)	95.1
Crude Oil | 2017 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	280	[2]
Total of Notional Volume (MMBtu's or Bbls)	102,200
Floor (Long) (Price per MMBtu)	80
Short Put (Price per MMBtu)	65
Ceiling (Short) (Price per MMBtu)	97.25
Fixed Price Swap 1 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	11,136
Total of Notional Volume (MMBtu's or Bbls)	4,064,500
Base Fixed Price (Price per MMbtu or Bbl)	4.06
Fixed Price Swap 1 | Natural Gas | 2015 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	400
Total of Notional Volume (MMBtu's or Bbls)	146,000
Base Fixed Price (Price per MMbtu or Bbl)	4
Fixed Price Swap 1 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	300	[2],[3]
Total of Notional Volume (MMBtu's or Bbls)	54,300	[3]
Base Fixed Price (Price per MMbtu or Bbl)	98.05	[3]
Fixed Price Swap 2 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	730,000
Base Fixed Price (Price per MMbtu or Bbl)	3.72
Fixed Price Swap 2 | Natural Gas | 2015 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	912,500
Base Fixed Price (Price per MMbtu or Bbl)	4.06
Fixed Price Swap 2 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	550	[2],[3]
Total of Notional Volume (MMBtu's or Bbls)	99,550	[3]
Base Fixed Price (Price per MMbtu or Bbl)	95.15	[3]
Fixed Price Swap 3 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	730,000
Base Fixed Price (Price per MMbtu or Bbl)	3.98
Fixed Price Swap 3 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	900	[2],[3]
Total of Notional Volume (MMBtu's or Bbls)	162,900	[3]
Base Fixed Price (Price per MMbtu or Bbl)	93.21	[3]
Fixed Price Swap 4 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	730,000
Base Fixed Price (Price per MMbtu or Bbl)	4.07
Fixed Price Swap 4 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	750	[2],[4]
Total of Notional Volume (MMBtu's or Bbls)	138,000	[4]
Base Fixed Price (Price per MMbtu or Bbl)	90.35	[4]
Fixed Price Swap 5 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	200,000	[2],[4]
Total of Notional Volume (MMBtu's or Bbls)	36,800,000	[4]
Base Fixed Price (Price per MMbtu or Bbl)	93	[4]
Fixed Price Swap 6 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	350	[2],[4]
Total of Notional Volume (MMBtu's or Bbls)	64,400	[4]
Base Fixed Price (Price per MMbtu or Bbl)	91.55	[4]
Fixed Price Swap 7 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	500	[2]
Total of Notional Volume (MMBtu's or Bbls)	182,500
Base Fixed Price (Price per MMbtu or Bbl)	91.1
Fixed Price Swap 8 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	270	[2]
Total of Notional Volume (MMBtu's or Bbls)	98,500
Base Fixed Price (Price per MMbtu or Bbl)	90.77
Costless Collar 1 | Natural Gas | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	3,000
Total of Notional Volume (MMBtu's or Bbls)	1,095,000
Floor (Long) (Price per MMBtu)	4
Ceiling (Short) (Price per MMBtu)	4.36
Costless Collar 2 | Natural Gas | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	1,825,000
Floor (Long) (Price per MMBtu)	4
Ceiling (Short) (Price per MMBtu)	4.55
Costless Collar 3 | Natural Gas | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	912,500
Floor (Long) (Price per MMBtu)	4
Ceiling (Short) (Price per MMBtu)	4.71
Costless Three Way Collar 2 | Crude Oil | 2015 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	345	[2]
Total of Notional Volume (MMBtu's or Bbls)	126,100
Floor (Long) (Price per MMBtu)	85
Short Put (Price per MMBtu)	65
Ceiling (Short) (Price per MMBtu)	97.8
Costless Three Way Collar 2 | Crude Oil | 2016 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	330	[2]
Total of Notional Volume (MMBtu's or Bbls)	120,780
Floor (Long) (Price per MMBtu)	80
Short Put (Price per MMBtu)	65
Ceiling (Short) (Price per MMBtu)	97.35
Costless Three Way Collar 2 | Crude Oil | 2017 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	242	[2]
Total of Notional Volume (MMBtu's or Bbls)	88,150
Floor (Long) (Price per MMBtu)	80
Short Put (Price per MMBtu)	60
Ceiling (Short) (Price per MMBtu)	98.7
Cost Less Three Way Collar 3 | Crude Oil | 2015 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	150	[2],[5]
Total of Notional Volume (MMBtu's or Bbls)	27,150	[5]
Floor (Long) (Price per MMBtu)	85	[5]
Short Put (Price per MMBtu)	65	[5]
Ceiling (Short) (Price per MMBtu)	96.25	[5]
Cost Less Three Way Collar 4 | Crude Oil | 2015 | Costless three-way collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	50	[2],[6]
Total of Notional Volume (MMBtu's or Bbls)	9,200	[6]
Floor (Long) (Price per MMBtu)	85	[6]
Short Put (Price per MMBtu)	65	[6]
Ceiling (Short) (Price per MMBtu)	96.25	[6]
Put Spread 1 | Crude Oil | 2014 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	200	[2],[7]
Total of Notional Volume (MMBtu's or Bbls)	24,400	[7]
Floor (Long) (Price per MMBtu)	93	[7]
Short Put (Price per MMBtu)	73	[7]
Put Spread 1 | Crude Oil | 2015 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	700	[2],[5]
Total of Notional Volume (MMBtu's or Bbls)	126,700	[5]
Floor (Long) (Price per MMBtu)	90	[5]
Short Put (Price per MMBtu)	70	[5]
Put Spread 1 | Crude Oil | 2016 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	550	[2]
Total of Notional Volume (MMBtu's or Bbls)	201,300
Floor (Long) (Price per MMBtu)	85
Short Put (Price per MMBtu)	65
Put Spread 1 | Crude Oil | 2017 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	500	[2]
Total of Notional Volume (MMBtu's or Bbls)	182,500
Floor (Long) (Price per MMBtu)	82
Short Put (Price per MMBtu)	62
Put Spread 2 | Crude Oil | 2015 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	250	[2]
Total of Notional Volume (MMBtu's or Bbls)	91,250
Floor (Long) (Price per MMBtu)	89
Short Put (Price per MMBtu)	69
Put Spread 2 | Crude Oil | 2016 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	300	[2]
Total of Notional Volume (MMBtu's or Bbls)	109,800
Floor (Long) (Price per MMBtu)	85.5
Short Put (Price per MMBtu)	65.5
Put Spread 2 | Crude Oil | 2018 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	425	[2],[8]
Total of Notional Volume (MMBtu's or Bbls)	103,275	[8]
Floor (Long) (Price per MMBtu)	80	[8]
Short Put (Price per MMBtu)	60	[8]
Put Spread 3 | Crude Oil | 2015 | Put spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	600	[2],[6]
Total of Notional Volume (MMBtu's or Bbls)	110,400	[6]
Floor (Long) (Price per MMBtu)	87	[6]
Short Put (Price per MMBtu)	67	[6]
[1]	For the period October to December 2014.
[2]	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
[3]	For the period January to June 2014.
[4]	For the period July to December 2014.
[5]	For the period January to June 2015.
[6]	For the period July to December 2015.
[7]	For the period September to December 2014.
[8]	For the period January to August 2018.

Derivative_Instruments_And_Hed4

Derivative Instruments And Hedging Activity (Schedule of Unamortized Put Premium) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Commodity derivative premium payable	$145	$0
Commodity derivative premium payable	7,000	0
Total unamortized put premium liabilities	$7,145	$0

Derivative_Instruments_And_Hed5

Derivative Instruments And Hedging Activity (Schedule of Future Amortization of Put Premium) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
September to December 2014	$145	'
January to December 2015	2,298	'
January to December 2016	2,408	'
January to December 2017	1,460	'
January to August 2018	834	'
Total unamortized put premium liabilities	$7,145	$0

Derivative_Instruments_And_Hed6

Derivative Instruments And Hedging Activity (Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]	'	'	'
Total derivatives not designated as hedging instruments	$3,764	$6,465	'
Amount of Gain/ (Loss) Recognized in Income on Derivatives	-4,752	7,236	12,068
(Loss) gain on commodity derivatives contracts	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Amount of Gain/ (Loss) Recognized in Income on Derivatives	-4,752	7,422	12,204
Interest expense	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Amount of Gain/ (Loss) Recognized in Income on Derivatives	0	-186	-136
Current assets	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Commodity derivative contracts, Assets	0	7,799	'
Other assets	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Commodity derivative contracts, Assets	7,545	1,369	'
Current liabilities	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Commodity derivative contracts, Liabilities	-3,403	-1,399	'
Long-term liabilities	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Commodity derivative contracts, Liabilities	($378)	($1,304)	'

Capital_Stock_Narrative_Detail

Capital Stock (Narrative) (Details) (USD $)

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

2 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 13, 2013

Jun. 03, 2012

Jun. 02, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 25, 2013

Jun. 23, 2011

24-May-11

Nov. 04, 2013

Oct. 29, 2013

Dec. 31, 2013

Nov. 01, 2013

Mar. 10, 2014

Dec. 31, 2013

Mar. 11, 2014

Jun. 29, 2011

Jun. 07, 2013

Jun. 07, 2013

Mar. 28, 2013

Dec. 31, 2013

Jun. 03, 2012

Apr. 01, 2009

Dec. 31, 2013

Dec. 31, 2013

On or after June 23, 2014

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Chesapeake Energy Corporation

Chesapeake Energy Corporation

Chesapeake Energy Corporation

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

Stock options

PBUs

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

At The Market Sales Agreement

At The Market Sales Agreement

At The Market Sales Agreement

At The Market Sales Agreement

Gastar Exploration USA

Gastar Exploration USA

Class of Stock [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common shares authorized for issuance (shares)

275,000,000

'

'

275,000,000

'

'

'

1,000

'

'

275,000,000

'

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, par value

$0.00

'

'

$0.00

'

'

'

'

'

'

$0.00

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock par value per share

$0.01

'

'

'

'

'

'

'

'

'

'

'

$0.01

'

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred shares authorized for issuance (shares)

40,000,000

'

'

'

'

'

'

'

'

'

'

'

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common shares reserved for the exercise of stock options (shares)

'

'

'

'

11,000,000

6,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,000,000

'

874,100

1,420,981

Shares available for future issuance (no more than) (shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,544,838

1,000,000

200,000

'

'

Amount paid to Chesapeake

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$10,800,000

$1,000,000

$10,800,000

'

'

'

'

'

Repurchase of common shares

9,753,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,800,000

9,800,000

'

'

'

'

'

'

Repurchase of common stock (shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,781,768

'

6,781,768

'

'

'

'

'

Common shares issued (shares)

61,211,658

66,432,609

'

'

'

'

'

'

750

'

'

'

750

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, shares sold (shares)

'

'

'

'

'

'

'

'

'

'

'

646,295

'

2,140,000

2,000,000

'

'

'

3,958,160

'

'

'

'

'

'

'

'

'

'

Redemption Price

'

'

'

'

'

'

$25

'

'

'

'

$25

'

'

$25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, dividend rate, percentage (percentage)

'

'

'

'

'

'

'

8.63%

'

'

'

'

'

'

10.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from issuance of preferred stock and preference stock

50,183,000

49,250,000

27,391,000

'

'

'

'

'

13,600,000

'

'

'

'

'

'

'

'

628,000

136,000

'

'

'

'

'

'

'

'

'

'

Preferred stock shares authorized to be sold in at the market sales agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,400,000

'

'

'

'

'

'

'

'

Preferred stock shares issued during current period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,906

26,203

'

'

'

'

'

'

'

'

'

Cumulative net proceeds from issuance of preferred stock

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

76,800,000

'

'

'

'

'

'

'

'

'

'

Period after change in control to redeem preferred stock (days)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

Payments of dividends

'

'

'

'

'

'

'

-8,500,000

-7,100,000

-1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercise of option to purchase additional shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

140,000

'

'

'

'

'

'

'

'

'

'

'

'

Total net proceeds from offering

'

'

'

'

'

'

'

'

'

'

'

'

'

50,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock redemption price per share

'

'

'

'

'

'

'

'

'

'

'

'

'

$25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate common shares with option to convert from preferred shares

'

'

'

'

'

'

'

'

'

'

'

'

'

11.5207

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock dividends

'

'

'

'

'

'

'

$9,378,000

$7,077,000

$1,024,000

'

'

'

'

'

$847,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividend rate due to change in control

'

'

'

'

'

'

'

'

'

'

'

'

'

12.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital_Stock_Schedule_of_Issu

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'
Stock options exercised (shares)	10,000		3,000
Unvested restricted shares	'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'
Restricted common shares granted (shares)	2,288,179		1,916,981
Restricted common shares vested (shares)	762,682		505,203
Common shares forfeited (shares)	224,500	[1]	141,458	[1]
Common shares canceled (shares)	512,862		74,463
[1]	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period.

Capital_Stock_Schedule_of_Pref

Capital Stock (Schedule of Preferred Stock Redemption Dates) (Details) (USD $)	Dec. 31, 2013
Prior to June 23, 2014	'
Auction Market Preferred Securities, Stock Series [Line Items]	'
Redemption Price	$25.25
On or after June 23, 2014	'
Auction Market Preferred Securities, Stock Series [Line Items]	'
Redemption Price	$25

Equity_Compensation_Plans_Narr

Equity Compensation Plans (Narrative) (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 03, 2012

Jun. 02, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 03, 2012

Apr. 01, 2009

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Stock options

Unvested restricted shares

PBUs

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

2006 Long-Term Stock Incentive Plan

Stock options

Stock options

Stock options

Unvested restricted shares

Unvested restricted shares

Unvested restricted shares

PBUs

PBUs

PBUs

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares available for future issuance (no more than) (shares)

'

'

'

'

'

'

'

'

1,544,838

1,000,000

200,000

'

'

'

'

'

'

'

'

'

Total number of shares that may be delivered (in shares)

'

'

'

'

'

'

'

'

'

5,000,000

'

'

'

'

'

'

'

'

'

'

Common shares reserved for the exercise of stock options (shares)

'

'

'

11,000,000

6,000,000

874,100

'

1,420,981

'

11,000,000

'

'

'

'

'

'

'

'

'

'

Stock grant expiration period (years)

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

Option vesting term (years)

'

'

'

'

'

'

'

'

'

'

'

'4 years

'2 years

'4 years

'3 years

'2 years

'4 years

'

'

'

Annual vesting percentage

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

Expected life (in years)

'

'

'

'

'

'6 years 3 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividend rate utilized in the Black-Scholes Merton valuation model

0.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected Forfeitures (percentage)

14.00%

15.50%

8.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized expense for outstanding awards

$2,700,000

'

'

'

'

'

$2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average period for recognition for unrecognized expense

'

'

'

'

'

'

'1 year 4 months 9 days

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage settlement of targeted number of PBUs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

0.00%

200.00%

Stock-based compensation expense

3,400,000

3,300,000

2,600,000

'

'

'

'

931,000

'

'

'

'

'

'

'

'

'

'

'

'

Total unrecognized expense for PBUs

'

'

'

'

'

'

'

$731,000

'

'

'

'

'

'

'

'

'

'

'

'

Equity_Compensation_Plans_Sche

Equity Compensation Plans (Schedule of Weighted Average Grant Date Fair Value) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Stock options	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Weighted average grant date fair value (in dollars per share)	$0		$0		$0
Intrinsic value of stock options exercised	$19	[1]	$2	[1]	$18	[1]
Grant date fair value of stock options vested	88		117		282
Unvested restricted shares	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Weighted average grant date fair value (in dollars per share)	$1.30		$2.09		$4.15
Grant date fair value of stock options vested	$2,725		$2,492		$2,436
[1]	Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.

Equity_Compensation_Plans_Shar

Equity Compensation Plans (Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable) (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'	'
Exercised	-10,000	-3,000
Stock options	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'	'
Outstanding at beginning of period	959,100	'
Granted	0	'
Exercised	-10,000	'
Canceled/Expired	0	'
Forfeited	-75,000	'
Outstanding at end of period	874,100	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'	'
Weighted-Average Exercise Price, Outstanding at beginning of period	11.31	'
Granted	0	'
Exercised	2.6	'
Canceled/Expired	0	'
Forfeited	8.18	'
Weighted-Average Exercise Price, Outstanding at end of period	11.68	'
Number of shares vested and exercisable	864,100	'
Weighted Average Exercise Price per Share	11.76	'
Weighted Average Remaining Contractual Term (in years)	'3 years 2 months 1 day	'
Aggregate Intrinsic Value (in thousands)	739	'

Equity_Compensation_Plans_Sche1

Equity Compensation Plans (Schedule of Non-vested Options) (Details) (Stock options, USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock options	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]	'	'	'
Outstanding non-vested options beginning balance	80,725	'	'
Stock options granted during the period	0	'	'
Vested	-50,725	'	'
Forfeited	-20,000	'	'
Outstanding non-vested options ending balance	10,000	80,725	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'	'	'
Outstanding non-vested options at beginning of period	$2.07	'	'
Granted	$0	$0	$0
Vested	$1.73	'	'
Forfeited	$2.58	'	'
Outstanding non-vested options at end of period	$2.74	$2.07	'
Weighted Average Exercise Price per Share	$4.27	'	'
Weighted Average Remaining Contractual Term (in years)	'14 days	'	'
Aggregate Intrinsic Value (in thousands)	$27	'	'

Equity_Compensation_Plans_Rest

Equity Compensation Plans (Restricted Stock Activity) (Details) (Unvested restricted shares, USD $)	12 Months Ended
	Dec. 31, 2013
Unvested restricted shares	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'
Unvested PBUs at December 31, 2012	2,760,446
Granted	2,288,179
Vested	-762,682
Forfeited	-512,862
Unvested PBUs at December 31, 2013	3,773,081
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'
Wieghted-Average Grant Date Fair Value, Outstanding at beginning of period	$2.75
Granted	$1.30
Vested	$3.57
Forfeited	$1.87
Weighted-Average Grant Date Fair Value, Outstanding at end of period	$1.82
Weighted Average Remaining Contractual Term (in years)	'8 years 8 months 4 days
Aggregate Intrinsic Value (in thousands)	$26,110,000

Equity_Compensation_Plans_Summ

Equity Compensation Plans (Summary of PBUs) (Details) (PBUs, USD $)	12 Months Ended
	Dec. 31, 2013
PBUs	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'
Unvested PBUs at December 31, 2012	0
Granted	1,192,889
Vested	0
Forfeited	-127,155
Unvested PBUs at December 31, 2013	1,065,734
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'
Unvested PBUs at December 31, 2012	$0
Granted	$1.56
Vested	$0
Forfeited	$0
Unvested PBUs at December 31, 2013	$1.56

Equity_Compensation_Plans_Sche2

Equity Compensation Plans (Schedule of Future Amortization of Unrecognized Compensation Cost) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
2014	$2,028
2015	594
2016	66
Total	$2,688

Interest_Expense_Schedule_of_C

Interest Expense (Schedule of Components of Interest Expense) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Interest expense:	'		'		'
Cash and accrued	$14,130,000		$1,992,000		$682,000
Amortization of deferred financing costs	2,322,000	[1],[2]	224,000	[1],[2]	249,000	[1],[2]
Capitalized interest	-3,284,000		-1,946,000		-818,000
Total interest expense	13,168,000		270,000		113,000
Deferred financing costs written off	1,200,000		'		'
Accretion of debt discount	716,000		'		'
Gastar Exploration USA	'		'		'
Interest expense:	'		'		'
Cash and accrued	13,978,000		1,993,000		681,000
Amortization of deferred financing costs	2,322,000	[1],[2]	224,000	[1],[2]	248,000	[1],[2]
Capitalized interest	-3,284,000		-1,946,000		-817,000
Total interest expense	$13,016,000		$271,000		$112,000
[1]	The year ended DecemberB 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. See Note 4, bLong-Term Debt - Second Amended and Restated Revolving Credit Facility.b
[2]	The year ended DecemberB 31, 2013 includes $716,000 of debt discount accretion related to the Notes.

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended			36 Months Ended	0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2007	Jun. 07, 2013
				Investor	Chesapeake Energy Corporation
Related Party Transaction [Line Items]	'	'	'	'	'
Common shares acquired by Chesapeake Energy Corporation (shares)	'	'	'	6,781,768	'
Amount paid to Chesapeake	'	'	'	'	$10,800,000
Repurchase of common shares	$9,753,000	$0	$0	'	$9,800,000
Repurchase of common stock (shares)	'	'	'	'	6,781,768

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
			Federal
Operating Loss Carryforwards [Line Items]	'	'	'
Federal statutory rate	'	'	35.00%
Net operating loss carryforwards	'	'	$333,900,000
Foreign tax credit carry forwards	$50,681,000	$50,681,000	'

Income_Taxes_Schedule_of_Incom

Income Taxes (Schedule of Income (loss) before Provision for Income Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
United States	$51,276	($152,322)	$285
Foreign	-1,934	-1,469	-1,025
Total income (loss) before income taxes	$49,342	($153,791)	($740)

Income_Taxes_Schedule_of_Compo

Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:	'	'	'
Federal	$0	$0	$0
State	0	0	0
Foreign	0	0	0
Provision for income taxes	0	0	0
Deferred:	'	'	'
Federal	-15,299	0	'
State	-743	0	'
Foreign	0	0	'
Income tax expense (benefit)	($16,042)	$0	$0

Income_Taxes_Income_Tax_Reconc

Income Taxes (Income Tax Reconciliation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Contingency [Line Items]	'	'	'
Expected income tax provision (benefit) at statutory rate	$11,655	($53,827)	($259)
State tax, tax effected	96	-2,562	0
Non-deductible stock-based compensation expense	605	560	441
Gain on acquisition of assets at fair value	-9,685	0	0
Non-deductible costs of migration from Canada to U.S.	95	0	0
Other	-49	15	10
Other changes in valuation allowance	-38,777	55,939	-89
Actual income tax provision	-16,042	0	0
Canada	'	'	'
Income Tax Contingency [Line Items]	'	'	'
Tax effect of Canadian tax rate differences	193	-125	-103
Loss of Canadian tax attributes due to migration from Canada	$19,825	$0	$0

Income_Taxes_Schedule_of_Defer

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax asset (liability):	'	'
Capital assets	($70,955)	($22,668)
Net operating loss carry forwards	122,675	93,339
Foreign tax credit carry forwards	50,681	50,681
Valuation allowance	-102,401	-121,352
Net deferred tax asset	0	0
Canada	'	'
Deferred tax asset (liability):	'	'
Capital assets	0	649
Share issuance costs	0	310
Foreign tax credit carry forwards	0	18,381
Valuation allowance	0	-19,340
Net deferred tax asset	$0	$0

Income_Taxes_Schedule_of_Unded

Income Taxes (Schedule of Undeducted Tax Pools) (Details) (Canada, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Canada	'	'
Loss Contingencies [Line Items]	'	'
Canadian and foreign exploration and development expense	$0	$2,597
Undeducted share issuance costs	0	1,239
Undeducted non-capital and capital loss carry forwards	$0	$73,522

Earnings_Per_Share_Schedule_of

Earnings Per Share (Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Net income (loss) attributable to common stockholder	($3,344)	($3,942)	$51,836	($4,586)	$2,934	($83,457)	($74,035)	($6,310)	$39,964	($160,868)	($1,764)
Weighted average common shares outstanding basic (shares)	57,433,550	57,359,357	62,398,472	63,864,527	63,669,744	63,601,645	63,541,739	63,336,437	60,220,115	63,538,362	63,003,579
Weighted average common shares outstanding diluted (shares)	57,433,550	57,359,357	63,813,423	63,864,527	63,678,597	63,601,645	63,541,739	63,336,437	63,618,401	63,538,362	63,003,579
Basic (dollars per share)	($0.06)	($0.07)	$0.83	($0.07)	$0.05	($1.31)	($1.17)	($0.10)	$0.66	($2.53)	($0.03)
Diluted (dollars per share)	($0.06)	($0.07)	$0.81	($0.07)	$0.05	($1.31)	($1.17)	($0.10)	$0.63	($2.53)	($0.03)
Common shares excluded from denominator as anti-dilutive (shares)	'	'	'	'	'	'	'	'	3,505	2,768,402	1,451,841
Unvested restricted shares	'	'	'	'	'	'	'	'	'	'	'
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Incremental shares	'	'	'	'	'	'	'	'	2,869,490	0	0
Common shares excluded from denominator as anti-dilutive (shares)	'	'	'	'	'	'	'	'	3,505	1,831,435	641,606
Stock options	'	'	'	'	'	'	'	'	'	'	'
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Incremental shares	'	'	'	'	'	'	'	'	26,095	0	0
Common shares excluded from denominator as anti-dilutive (shares)	'	'	'	'	'	'	'	'	0	936,967	810,235
PBUs	'	'	'	'	'	'	'	'	'	'	'
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Incremental shares	'	'	'	'	'	'	'	'	502,701	0	0

Commitments_And_Contingencies_1

Commitments And Contingencies (Narrative) (Details) (USD $)

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 17, 2010

Jun. 07, 2013

Dec. 31, 2013

Aug. 07, 2013

Jun. 07, 2013

Mar. 28, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Chesapeake Exploration LLC and Chesapeake Energy Corporation vs Gastar Exploration Ltd, Gastar Exploration Texas LP, and Gastar Exploration Texas LLC

Gastar Exploration Ltd vs US Specialty Ins Co and Axis Ins Co

Chesapeake Energy Corporation

Hilltop Resort

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Capacity

Gastar Exploration USA Inc v Williams Ohio Valley Midstream LLC

Chesapeake Energy Corporation

Chesapeake Energy Corporation

ETC Texas Pipeline Ltd

ETC Texas Pipeline Ltd

ETC Texas Pipeline Ltd

Hilltop Resort

Hilltop Resort

SEI Energy LLC

Atinum and SEI Energy

Natural Gas Gross Production Volume

Capacity

Capacity

Capacity

Capacity

Capacity

Capacity

Capacity

MMcf

Treating Capacity

Transportation Capacity

Natural Gas Gross Production Volume

MMcf

MMcf

MMcf

Loss Contingencies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Office lease expense

$372,000

$377,000

$160,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss contingency, damages sought, value

'

'

'

'

101,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount paid by Chesapeake for the purchase of shares

'

'

'

'

76,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares purchased by Chesapeake (shares)

'

'

'

'

5,430,329

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock split, conversion ratio

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount paid to Chesapeake

'

'

'

'

'

'

10,800,000

'

'

1,000,000

10,800,000

'

'

'

'

'

'

'

Repurchase of common shares

9,753,000

0

0

'

'

'

9,800,000

'

'

9,800,000

'

'

'

'

'

'

'

'

Repurchase of common stock (shares)

'

'

'

'

'

'

6,781,768

'

'

'

6,781,768

'

'

'

'

'

'

'

Litigation settlement, gross

'

'

'

'

'

21,200,000

'

'

'

80,000,000

'

'

'

'

'

'

'

'

Acquisition of oil and natural gas properties

251,096,000

0

0

'

'

'

'

'

'

69,400,000

'

'

'

'

'

'

'

'

Damages sought in arbitration matter

'

'

'

'

'

'

'

'

612,000

'

'

'

'

'

'

'

'

'

Directors and officers liability coverage limit

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Natural gas production term (years)

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'15 years

'

'5 years

'10 years

Daily production (in Mcf)

'

'

'

'

'

'

'

50

'

'

'

'

50

150

'

35

'

'

Minimum gathering gross production volume term (years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

Gathering fee on the initial gross production (in Bcf)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000

'

'

Gathering fee on the initial gross production (in dollars per Mcf)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.325

'

'

Minimum gathering fee per Mcf (in dollars per Mcf)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.225

'

'

Cumulative gross production (in Bcf)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000

'

'

Payment as a result of actual production volumes being less than minimum contractual volume requirements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,800,000

'

'

Asset retirement obligation

6,063,000

6,963,000

8,275,000

7,249,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset retirement obligation, current

633,000

358,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset retirement obligation, non-current

$5,430,000

$6,605,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitments_And_Contingencies_2

Commitments And Contingencies (Schedule of Future Minimum Rental Commitments) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]	'
2014	$681
2015	602
2016	453
2017	142
2018	117
Total	$1,995

Concentration_of_Risk_and_Sign2

Concentration of Risk and Significant Customers (Schedule of Concentration Risk) (Details) (Natural gas, oil and NGLs revenues excluding realized hedge impact)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
SEI | Customer Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	56.00%		47.00%		8.00%
Sunoco | Customer Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	16.00%		0.00%		0.00%
Clearfield Appalachian | Customer Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	8.00%		14.00%		0.00%
ETC | Customer Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	8.00%		24.00%		69.00%
Plains Marketing LP | Customer Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	1.00%		2.00%		10.00%
Marcellus Shale and Other Appalachia | Geographic Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	65.00%		72.00%		15.00%
Mid-Continent | Geographic Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	26.00%		0.00%		0.00%
Hilltop Area, East Texas | Geographic Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	9.00%	[1]	27.00%	[1]	79.00%	[1]
Powder River Basin | Geographic Concentration Risk	'		'		'
Concentration Risk [Line Items]	'		'		'
Concentration risk, percentage	0.00%	[2]	1.00%	[2]	6.00%	[2]
[1]	The Company's working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013.
[2]	The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012.

Statement_Of_Cash_Flows_Supple2

Statement Of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Significant Noncash Transactions [Line Items]	'	'	'
Cash paid for interest, net of capitalized amounts	$7,341	$39	$0
Non-cash transactions:	'	'	'
Capital expenditures excluded from accounts payable and accrued drilling costs	582	4,666	4,600
Capital expenditures excluded from accounts receivable	-4,077	-929	0
Capital expenditures excluded from prepaid expenses	0	0	48
Asset retirement obligation included in natural gas and oil properties	-1,302	1,164	492
Asset retirement obligation sold/assigned to operator	-4,354	-2,227	0
Application of advances to operators	19,755	7,441	6,529
Other	47	-36	0
Gastar Exploration USA	'	'	'
Other Significant Noncash Transactions [Line Items]	'	'	'
Cash paid for interest, net of capitalized amounts	7,341	39	0
Non-cash transactions:	'	'	'
Capital expenditures excluded from accounts payable and accrued drilling costs	582	4,666	4,600
Capital expenditures excluded from accounts receivable	-4,077	-929	0
Capital expenditures excluded from prepaid expenses	0	0	48
Asset retirement obligation included in natural gas and oil properties	-1,302	1,164	492
Asset retirement obligation sold/assigned to operator	-4,354	-2,227	0
Application of advances to operators	19,755	7,441	6,529
Due to (from) Parent - transfer to equity, net	15,495	5,295	2,612
Other	$47	($36)	$0

Quarterly_Consolidated_Financi2

Quarterly Consolidated Financial Data - Unaudited (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Sep. 30, 2011

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jun. 07, 2013

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Chesapeake Assets

Chesapeake Assets

Gastar Exploration USA

Gastar Exploration USA

Schedule Of Quarterly Financial Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenues

$26,725

$18,840

$30,926

$11,264

$17,422

$9,443

$13,921

$9,154

'

'

'

'

'

$26,725

$18,840

$30,926

$11,264

$17,422

$9,443

$13,921

$9,154

'

'

'

'

'

Income (loss) from operations

5,178

1,626

13,809

-1,849

5,245

[1]

-81,443

[1]

-72,237

[1]

-5,052

[1]

'

'

18,764

-153,528

-631

5,957

[2]

2,086

[2]

14,157

[2]

-1,628

[2]

5,566

[1]

-80,973

[1]

-71,980

[1]

-4,662

[1]

'

'

'

'

'

Income (loss) before provision for income taxes (1)

-16,406

[3]

-1,808

[3]

53,970

[3]

-2,456

[3]

5,064

-81,473

-72,308

-5,074

'

'

'

'

'

-15,483

-1,363

54,312

-2,231

5,382

-81,007

-72,011

-4,686

'

'

'

'

'

Net income (loss)

-364

-1,808

53,970

-2,456

5,064

-81,473

-72,308

-5,074

'

'

49,342

-153,791

-740

559

-1,363

54,312

-2,231

5,382

-81,007

-72,011

-4,686

51,277

-152,322

285

'

'

Dividend on preferred stock attributable to non-controlling interest

2,980

2,134

2,134

2,130

2,130

1,984

1,727

1,236

'

'

-9,378

-7,077

-1,024

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends on preferred stock

'

'

'

'

'

'

'

'

'

'

'

'

'

2,980

2,134

2,134

2,130

2,130

1,984

1,727

1,236

'

'

'

'

'

Net income (loss) attributable to common stockholder

-3,344

-3,942

51,836

-4,586

2,934

-83,457

-74,035

-6,310

'

'

39,964

-160,868

-1,764

-2,421

-3,497

52,178

-4,361

3,252

-82,991

-73,738

-5,922

'

'

'

'

'

Basic (in dollars per share)

($0.06)

($0.07)

$0.83

($0.07)

$0.05

($1.31)

($1.17)

($0.10)

'

'

$0.66

($2.53)

($0.03)

'

'

'

'

'

'

'

'

'

'

'

'

'

Diluted (in dollars per share)

($0.06)

($0.07)

$0.81

($0.07)

$0.05

($1.31)

($1.17)

($0.10)

'

'

$0.63

($2.53)

($0.03)

'

'

'

'

'

'

'

'

'

'

'

'

'

Basic (shares)

57,433,550

57,359,357

62,398,472

63,864,527

63,669,744

63,601,645

63,541,739

63,336,437

'

'

60,220,115

63,538,362

63,003,579

'

'

'

'

'

'

'

'

'

'

'

'

'

Diluted (shares)

57,433,550

57,359,357

63,813,423

63,864,527

63,678,597

63,601,645

63,541,739

63,336,437

'

'

63,618,401

63,538,362

63,003,579

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain on acquisition of assets at fair value

'

'

43,712

'

'

'

'

'

'

'

27,670

0

0

'

'

'

'

'

'

'

'

'

'

'

27,670

'

Deferred tax liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16,042

Impairment of natural gas and oil properties

'

$0

$0

'

'

$78,054

$72,733

'

$0

$0

$0

$150,787

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Loss from operations for the second and third quarters of 2012 include a quarterly ceiling test impairment charge of $72.7 million and $78.1 million, respectively.

[2]

Income before provision for income taxes for the second quarter of 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.

[3]

Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.

Supplemental_Oil_and_Gas_Discl2

Supplemental Oil and Gas Disclosures - Unaudited (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Extractive Industries [Abstract]	'	'	'
Asset retirement costs	$3.40	$4.80	$5.80

Supplemental_Oil_and_Gas_Discl3

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Proved properties:	$935,773	$671,193	$514,357
Total proved properties	96,220	67,892	78,302
Total natural gas and oil properties	1,031,993	739,085	592,659
Accumulated depreciation, depletion and amortization	-177,790	-145,631	-120,436
Net capitalized costs	516,264	255,515	285,071
United States	'	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Proved properties:	935,773	671,193	514,357
Total proved properties	96,220	67,892	78,302
Impairment of proved natural gas and oil properties	($337,939)	($337,939)	($187,152)

Supplemental_Oil_and_Gas_Discl4

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) (United States, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
United States	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Proved property acquisition	$189,594,000	[1]	$0	[1]	$0	[1]
Unproved property acquisition	71,472,000	[2]	25,676,000	[2]	19,552,000	[2]
Exploration	36,893,000		10,041,000		47,668,000
Development	53,058,000		111,878,000		18,167,000
Total costs incurred	351,017,000		147,595,000		85,387,000
Adjustment for fair value of acquisition	46,300,000		'		'
Downward adjustment for fair value of acquisition	($2,600,000)		'		'
[1]	The 2013 property acquisition costs excludes a downward adjustment of $2.6 million for fair value of acquisition.
[2]	The 2013 property acquisition costs excludes $46.3 million of adjustment for fair value of acquisition.

Supplemental_Oil_and_Gas_Discl5

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Results of Operations for Oil and Gas Producing Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Oil, condensate, natural gas and NGLs sales, including commodity derivatives	$87,755	$49,940	$40,235
Production expenses	-18,113	-13,408	-13,751
Impairment of oil and natural gas properties	0	-150,787	0
Depreciation, depletion and amortization	-32,158	-25,195	-14,989
Results of producing activities	$37,484	($139,450)	$11,495
Depreciation, depletion and amortization per Mcfe and MBoe	1.66	11.41	11.7

Supplemental_Oil_and_Gas_Discl6

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Oil and Gas Net Production, Average Sales Price and Average Production Costs) (Details)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Henry Hub

Henry Hub

Henry Hub

WTI posting

WTI posting

WTI posting

WTI spot

WTI spot

WTI spot

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Natural gas (per MMBtu):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Oil (per Bbl):

Average Sales Price and Production Costs Per Unit of Production [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Key natural gas and oil prices

3.67

[1]

3.61

[1]

3.44

[1]

2.95

[1]

2.76

[1]

2.83

[1]

3.15

[1]

3.73

[1]

4.12

[1]

4.16

[1]

4.21

[1]

4.1

[1]

96.78

[1]

91.69

[1]

88.13

[1]

89.17

[1]

91.21

[1]

91.48

[1]

92.17

[1]

94.65

[1]

92.71

[1]

91

[1]

86.6

[1]

80.04

[1]

3.67

2.76

4.12

0

91.21

75.96

96.78

94.71

0

[1]

For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Supplemental_Oil_and_Gas_Discl7

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	MBoe		MBoe		MBoe
	Mcfe		Mcfe		Mcfe
Proved Developed And Undeveloped Reserves [Roll Forward]	'		'		'
Proved reserves as of the beginning of the period, equivalents	180,909,000	[1],[2]	19,953,000	[3],[4]	50,260,000	[1],[2]
Extensions and discoveries	15,483,000	[3],[4],[5]	14,861,000	[3],[4],[6]	14,106,000	[3],[4]
Revisions of previous estimates (6)	1,729,000	[3],[4]	-2,230,000	[3],[4]	-1,248,000	[3],[4],[7]
Production	-3,237,000	[3],[4]	-2,208,000	[3],[4]	-1,281,000	[3],[4]
Purchases in place	14,639,000	[3],[4]	7,000	[3],[4]	'
Sales in place	-4,132,000	[3],[4]	-231,000	[3],[4]	'
Proved reserves at the end of the period. equivalents	327,805,000	[1],[2]	180,909,000	[1],[2]	19,953,000	[3],[4]
Proved developed reserves	185,349,000	[1],[2]	126,653,000	[1],[2]	13,087,000	[3],[4]
Proved undeveloped reserves	142,456,000	[1],[2]	54,256,000	[1],[2]	6,867,000	[3],[4]
Total	327,805,000	[1],[2]	180,909,000	[1],[2]	19,954,000	[3],[4]
Percentage of extensions and discoveries from successful drilling results in Marcellus Shale	74.00%		'		'
Natural Gas	'		'		'
Proved Developed And Undeveloped Reserves [Roll Forward]	'		'		'
Proved reserves as of the beginning of the period	131,010	[1]	91,652	[1]	49,892	[1]
Extensions and discoveries	52,750	[1],[5]	57,835	[1],[6]	56,364	[1]
Revisions of previous estimates	8,114	[1]	-6,518	[1]	-7,286	[1],[7]
Production	-13,366	[1]	-10,564	[1]	-7,318	[1]
Purchases in place	26,961	[1]	0	[1]	'
Sales in place	-24,759	[1]	-1,395	[1]	'
Proved reserves as of the end of the period	180,710	[1]	131,010	[1]	91,652	[1]
Proved developed reserves	114,195	[1]	95,602	[1]	65,061	[1]
Proved undeveloped reserves	66,515	[1]	35,408	[1]	26,591	[1]
Total	180,710	[1]	131,010	[1]	91,652	[1]
Natural Gas Liquids	'		'		'
Proved Developed And Undeveloped Reserves [Roll Forward]	'		'		'
Proved reserves as of the beginning of the period	4,922,000	[8]	2,757,000	[8]	0	[8]
Extensions and discoveries	2,306,000	[5],[8]	2,783,000	[6],[8]	2,767,000	[8]
Revisions of previous estimates	714,000	[8]	-348,000	[8]	11,000	[7],[8]
Production	-494,000	[8]	-270,000	[8]	-21,000	[8]
Purchases in place	2,350,000	[8]	0	[8]	'
Sales in place	0	[8]	0	[8]	'
Proved reserves as of the end of the period	9,798,000	[8]	4,922,000	[8]	2,757,000	[8]
Proved developed reserves	6,025,000	[8]	3,215,800	[8]	1,339,000	[8]
Proved undeveloped reserves	3,773,000	[8]	1,706,000	[8]	1,418,000	[8]
Total	9,798,000	[8]	4,922,000	[8]	2,757,000	[8]
Oil	'		'		'
Proved Developed And Undeveloped Reserves [Roll Forward]	'		'		'
Proved reserves as of the beginning of the period	3,394,000	[8]	1,921,000	[8]	61,000	[8]
Extensions and discoveries	4,385,000	[5],[8]	2,439,000	[6],[8]	1,945,000	[8]
Revisions of previous estimates	-337,000	[8]	-796,000	[8]	-45,000	[7],[8]
Production	-515,000	[8]	-177,000	[8]	-40,000	[8]
Purchases in place	7,796,000	[8]	7,000	[8]	'
Sales in place	-5,000	[8]	0	[8]	'
Proved reserves as of the end of the period	14,718,000	[8]	3,394,000	[8]	1,921,000	[8]
Proved developed reserves	5,834,000	[8]	1,959,000	[8]	904,000	[8]
Proved undeveloped reserves	8,884,000	[8]	1,435,000	[8]	1,017,000	[8]
Total	14,718,000	[8]	3,394,000	[8]	1,921,000	[8]
[1]	Million cubic feet or million cubic feet equivalent, as applicable
[2]	Oil, condensate and NGLs volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one barrel of oil, condensate or NGLs.
[3]	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
[4]	Thousand barrels of oil, condensate or NGLs equivalent.
[5]	74% of the 2013 extensions and discoveries resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
[6]	The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery.
[7]	The 2011 downward revision of previous estimates of natural gas is primarily attributed to the decision to forgo an East Texas PUD location due to low natural gas prices which would have resulted in drilling beyond the five-year maximum carry period.
[8]	Thousand barrels

Supplemental_Oil_and_Gas_Discl8

Supplemental Oil and Gas Disclosures - Unaudited (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves) (Details) (United States, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
United States	'	'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'		'
Future cash inflows	$2,103,023	$672,142		$584,067
Future production costs	-588,568	-167,864		-101,938
Future development costs	-296,666	-83,697		-57,843
Future income taxes	-76,701	0	[1]	-33,732
Future net cash flows	1,141,088	420,581		390,554
10% annual discount for estimated timing of cash flows	-625,259	-213,772		-177,771
Standardized measure of discounted future cash flows	$515,829	$206,809		$212,783
[1]	No future taxes payable has been included in the determination of discounted future net cash flows for 2012 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows.

Supplemental_Oil_and_Gas_Discl9

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) (United States, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
United States	'	'	'
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Beginning of period	$206,809	$212,783	$67,282
Extensions and discoveries, less related costs	196,448	112,390	180,539
Sale of natural gas and oil, net of production costs	-74,394	-29,110	-24,148
Purchases of reserves in place	247,208	64	'
Sales of reserves in place	-9,063	-216	'
Revisions of previous quantity estimates	6,191	-30,959	-9,323
Net change in income tax	-76,701	4,334	-4,334
Net change in prices and production costs	79,820	-98,589	12,394
Accretion of discount	1,211	1,152	5,011
Development costs incurred	23,567	19,702	1,482
Net change in estimated future development costs	-97,461	2,518	4,541
Change in production rates (timing) and other	12,194	12,740	-20,661
End of period	$515,829	$206,809	$212,783