Gastar Exploration (GST) 8-K Results of Operations and Financial Condition

Exhibit 99.1

For Immediate Release NEWS RELEASE   Contacts: Gastar Exploration Inc. Michael A. Gerlich, Chief Financial Officer 713-739-1800 / mgerlich@gastar.com   Investor Relations Counsel:
Lisa Elliott, Dennard▪Lascar Associates: 713-529-6600 / lelliott@DennardLascar.com

GASTAR EXPLORATION INC. REPORTS

THIRD QUARTER 2014 RESULTS

• Revenues from liquids grew to 80% of total production revenues

• 24 gross Mid-Continent Hunton wells completed or in progress during Q3

• Raised $101.3 million with public offering of common stock

• Announces revised 2015 capital budget and financial and operations guidance

HOUSTON, November 6, 2014 - Gastar Exploration Inc. (NYSE MKT: GST) (“Gastar”) today reported financial and operating results for the three and nine months ended September 30, 2014.

Net income attributable to Gastar’s common stockholders for the third quarter of 2014 was $9.8million, or $0.15 per diluted share. Excluding the impact of a $7.6 million gain resulting from the mark-to-market of outstanding hedge positions, adjusted net income attributable to common stockholders was $2.2 million, or $0.03 per diluted share. This compares to a third quarter 2013 net loss of $3.9 million, or a loss of $0.07 per diluted share, and third quarter 2013 adjusted net income of $1.9 million, or $0.03 per diluted share, excluding the impact of a $5.0 million loss resulting from the mark-to-market of outstanding hedge positions and non-recurring charges of $850,000. (See the accompanying reconciliation of net income (loss) to net income excluding special items at the end of this news release.)

Adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“adjusted EBITDA”) for the third quarter of 2014 was $25.2 million, an increase of 48% compared to $17.1 million for the third quarter of 2013 and a 14% decrease compared to $29.4 million for the second quarter of 2014, which benefited from an arbitration settlement. (See the accompanying reconciliation of net income (loss) to adjusted EBITDA, a non-GAAP number, at the end of this news release.)

Revenues from oil, condensate, natural gas and natural gas liquids (“NGLs”), before the impact of hedging activities, increased 46% to $35.1 million in the third quarter of 2014, up from $24.1 million for

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the third quarter of 2013. The increase in oil, condensate, natural gas and NGLs revenues was primarily the result of a 47% increase in weighted average equivalent realized prices offset by a 1%decline in production compared to the third quarter of 2013.

Revenues from liquids (oil, condensate and NGLs) represented approximately 80% of total production revenues in the third quarter of 2014, compared to 58% for the third quarter of 2013 and 72%during the second quarter of 2014, excluding the benefit from an arbitration settlement. We had hedges in place covering approximately 87% of our natural gas production, 43% of our oil and condensate production and 85% of our NGLs production for the third quarter of 2014. Commodity derivative contracts settled during the periods resulted in a $1.0 million reduction in revenue for the third quarter of 2014, compared to a $259,000 reduction in revenue for the third quarter of 2013 and a $3.5 million reduction in revenue for the second quarter of 2014. We continue to maintain an active hedging program covering a portion of estimated future production, which is reported in our periodic filings with the U.S. Securities and Exchange Commission (“SEC”).

Average daily production for the third quarter of 2014 was 9.8 thousand barrels of oil equivalent per day (“MBoe/d”) (on a 6:1 gas (Mcf) to liquids (barrel) equivalent basis), a 1% decrease compared to the third quarter of 2013 and a 3% increase compared to the second quarter of 2014. Oil, condensate and NGLs as a percentage of production volumes were 48% in the third quarter of 2014 compared to 29% in the third quarter of 2013 and 48% in the second quarter of 2014.

J. Russell Porter, Gastar's President and CEO, commented, “During the third quarter 2014, we continued to de-risk our acreage in multiple formations, including the lower Hunton Limestone in the Mid-Continent and the Utica/Point Pleasant in Appalachia. Production rates for many of our wells that were brought online during the third quarter, both operated and non-operated, came in at or above our type curve expectations, reflecting the ability of our drilling opportunities to generate attractive rates of return in the current commodity price environment.”

“Our first Utica/Point Pleasant well, the Simms U-5H in Marshall County, West Virginia, continues to perform very well with the first 30 days of production averaging 19.8 MMcf of natural gas per day, and we continue to see excellent results from surrounding operators. To further de-risk our West Virginia acreage for this formation, we will spud the lateral on our second Utica/Point Pleasant well in Marshall County, the Blake U-7H, later this month and expect to drill a third well in Wetzel County, West Virginia in early 2015. Since we have very few lease expiration issues related to our West Virginia acreage and no near-term drilling commitments, we are well positioned to maintain a flexible strategy for both

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Marcellus Shale and Utica/Point Pleasant development and plan to postpone further development in this area until natural gas prices improve.”

“The strong performance of recent wells, combined with an active drilling and completion program in the fourth quarter, is expected to drive production rates significantly higher in the first quarter of 2015. In the Marcellus Shale, we anticipate completing 10 gross wells during the fourth quarter of 2014 and in the Mid-Continent, we expect to complete nine gross wells (operated and non-operated) before year-end. Although we are taking a more cautious approach to our 2015 capital expenditure plan than originally announced, as discussed below we are still targeting in excess of a 40% increase in year-over-year production for 2015.”

The following table provides a summary of Gastar’s production volumes and average commodity prices for the three and nine months ended September 30, 2014 and 2013:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2014		2013		2014		2013
Production:
Oil and condensate (MBbl)	250		128		660		333
Natural gas (MMcf)	2,826		3,866		8,579		10,257
NGLs (MBbl)	180		137		543		347
Total production (MBoe)	901		909		2,633		2,390
Daily Production:
Oil and condensate (MBbl/d)	2.7		1.4		2.4		1.2
Natural gas (MMcf/d)	30.7		42.0		31.4		37.6
NGLs (MBbl/d)	2.0		1.5		2.0		1.3
Total daily production (MBoe/d)	9.8		9.9		9.6		8.8
Average sales price per unit(1):
Oil and condensate per Bbl, including impact of hedging(2)	$	88.77	$	67.92	$	85.47	$	68.54
Oil and condensate per Bbl, excluding impact of hedging	$	91.17	$	73.40	$	89.06	$	68.26
Natural gas per Mcf, including impact of hedging(2)	$	2.56	$	2.95	$	3.34	$	3.38
Natural gas per Mcf, excluding impact of hedging	$	2.53	$	2.61	$	3.73	$	2.94
NGLs per Bbl, including impact of hedging(2)	$	26.13	$	27.54	$	28.09	$	30.80
NGLs per Bbl, excluding impact of hedging	$	28.56	$	33.79	$	31.99	$	30.01
Average sales price per Boe, including impact of hedging(2)	$	37.87	$	26.23	$	38.11	$	28.53
Average sales price per Boe, excluding impact of hedging	$	38.94	$	26.52	$	41.07	$	26.47

_____________________________

(1) The nine months ended September 30, 2014 pricing exclude the benefit of a revenue adjustment related to an arbitration settlement.

(2) The impact of hedging includes the gain (loss) on commodity derivative contracts settled during the periods presented.

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Lease operating expenses (“LOE”) were $4.1 million for the third quarter of 2014, compared to $2.2 million in the third quarter of 2013 and $5.1 million in the second quarter of 2014, exclusive of the benefit of an arbitration settlement. The increase in LOE compared to the third quarter of 2013 was primarily due to additional expenses from new wells as well as higher overall costs associated with producing liquids versus natural gas. Compared to the second quarter of 2014, the third quarter of 2014 LOE benefitted from a transition to gas lift versus submersible electric pumps on certain operated Oklahoma properties, and the second quarter of 2014 included approximately $350,000 of production enhancing costs for pump repair and scale removal that were not incurred during the third quarter of 2014. LOE per Boe of production was $4.59 in the third quarter of 2014 versus $2.41 in the third quarter of 2013 and $5.88 in the second quarter of 2014 (exclusive of the benefit of an arbitration settlement).

Depreciation, depletion and amortization expense (“DD&A”) was $11.1 million in the third quarter of 2014, up from $8.5 million in the third quarter of 2013 and $10.3 million in the second quarter of 2014. The year-over-year increase in DD&A expense is the result of higher cost, liquids-focused acquisitions and drilling. The DD&A rate for the third quarter of 2014 was $12.33 per Boe compared to $9.31 per Boe for the third quarter of 2013 and $11.94 in the second quarter of 2014.

General and administrative (“G&A”) expense was $4.0 million in the third quarter of 2014 and the third quarter of 2013. G&A expense for the third quarter of 2014 included $1.2 million of non-cash, stock-based compensation expense, versus $574,000 in the third quarter of 2013. Excluding stock compensation expense, cash G&A expense decreased to $2.8 million in the third quarter of 2014 from $3.4 million in the third quarter of 2013. This decrease was primarily due to severance costs incurred in the third quarter of 2013 related to the disposition of our East Texas property as well as acquisition-related costs incurred during the same period, partially offset by the current year’s higher personnel costs in association with our growing asset base.

Interest expense totaled $7.0 million in the third quarter of 2014, compared to $3.4 million in the third quarter of 2013. The increase was the result of the issuance in November of 2013 of an additional $125.0 million of 8 5/8% Senior Secured Notes, resulting in a total of $325.0 million outstanding, due May 2018.

Operations Review and Update

Mid-Continent

Currently, we have one operated rig running outside of our joint venture AMI acreage and three non-operated rigs running on our AMI acreage. Net production from the Mid-Continent area increased to

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an average of 4.5 MBoe/d in the third quarter of 2014, compared to 1.2 MBoe/d in the third quarter of 2013 and 4.1 MBoe/d in the second quarter of 2014. Third quarter 2014 Mid-Continent production consisted of approximately 51% oil, 29% natural gas and 20% NGLs, yielding a total liquids production percentage of 71%. Within our AMI acreage, there were seven gross (2.8 net) non-operated wells placed on production during the third quarter of 2014. Subsequent to the end of the third quarter 2014 within our Mid-Continent AMI acreage, two gross (0.8 net) non-operated wells were placed on production, seven gross (2.8 net) non-operated wells have been drilled and are awaiting completion, and three gross (1.3 net) non-operated wells are being drilled.

The table below shows wells brought on production or commenced drilling operations since the beginning of the third quarter of 2014 within our original AMI in the Hunton Limestone formation (all of which are operated by our joint venture partner):

				Cumulative Production Averages(2)
Well Name	Current Working Interest	Approximate Lateral Length (in feet)	Peak Production Rates(1) (BOE/d)	BOE/d	% Oil	Date of First Production or Status(3)	Approximate Gross Costs to Drill & Complete ($ millions)
Vaverka 1-20H	46.9%	4,400	N/A	192	68%	July 10, 2014	$5.7
Sasquatch 1-23H	44.2%	4,800	581	372	66%	July 27, 2014	$5.6
Jam 1-4H	36.8%	4,900	477	348	57%	August 8, 2014	$5.9
Yeti 1-29H	32.8%	5,000	1,015	687	57%	August 26, 2014	$6.0
Danny Ray 1-30H	31.7%	5,000	N/A	312	71%	August 29, 2014	$6.0
Cline 1-13H	50.0%	5,100	N/A	85	88%	September 6, 2014	$6.1
Michael J 1-18H	33.3%	5,000	N/A	362	80%	September 29, 2014	$6.0
Shimanek 1-2H	48.9%	5,000	1,829	1,756	79%	October 9, 2014	$6.0
Hobbs Ranch 1-19H	29.5%	4,400	N/A	573	84%	October 13, 2014	$5.7
Snowman 1-19H	36.1%	4,900	N/A	N/A	N/A	WOC	$5.9
Breckenridge 1-2H	25.4%	4,800	N/A	N/A	N/A	WOC	$5.8
Polar Bear 1-20H	45.6%	4,400	N/A	N/A	N/A	WOC	$5.7
Joyce 1-10H(4)	51.7%	5,300	N/A	N/A	N/A	WOC	$6.3
Falcon 1-5H	38.5%	4,700	N/A	N/A	N/A	WOC	$5.8
Bear Claw 1-28H	38.3%	5,000	N/A	N/A	N/A	WOC	$6.0
Barry 1-6H	42.6%	5,000	N/A	N/A	N/A	WOC	$6.0
The River 1-22H	28.3%	4,400	N/A	N/A	N/A	Drilling	$5.7
Boss Hogg 1-14H	43.8%	4,400	N/A	N/A	N/A	Drilling	$5.7
Hubbard 1-23H(5)	57.0%	4,600	N/A	N/A	N/A	Drilling	$5.8

_________________________________

(1) Represents highest daily gross BOE rate.

(2) Represents gross average production for actual producing days through October 30, 2014.

(3) WOC - waiting on completion.

(4) After payout working interest is 45.0%.

(5) After payout working interest is 49.9%.

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Within our operated acreage in Oklahoma, we currently have six gross (5.6 net) producing wells. We have also drilled two gross horizontal wells, the Deer Draw 21-4H and Deer Draw 21-5H, targeting the lower Hunton Limestone within the West Edmond Hunton Lime Unit (“WEHLU”) that are awaiting completion and should commence flow back operations within the next week. Additionally, we are currently drilling a vertical well, the Warsaw 33-1, to test the upper and lower Hunton Limestone formations in the southern portion of our WEHLU acreage. Since no proved reserves are currently booked for the lower Hunton Limestone formation on the southern portion of our WEHLU acreage, the results of the Warsaw well and subsequent horizontal offset drilling could have a meaningful impact on our future reserve base.

The table below shows wells brought on production or commenced drilling operations since the beginning of the third quarter of 2014 within our operated acreage in the Hunton Limestone formation:

				Cumulative Production Averages(2)
Well Name	Current Working Interest	Approximate Lateral Length (in feet)	Peak Production Rates(1) (BOE/d)	BOE/d	% Oil	Date of First Production or Status(3)	Approximate Gross Costs to Drill & Complete ($ millions)
Easton 22-1H	98.3%	4,900	673	433	90%	July 30, 2014	$7.5
Easton 22-2H	98.3%	6,500	855	463	93%	August 5, 2014	$3.9
Horseshoe 3-1H	99.3%	5,100	N/A	263	49%	September 16, 2014	$6.2
Deer Draw 21-4H	98.3%	5,900	N/A	N/A	N/A	WOC	$4.3
Deer Draw 21-5H	98.3%	4,900	N/A	N/A	N/A	WOC	$5.5
Warsaw 33-1(3)	98.3%	N/A	N/A	N/A	N/A	Drilling	$3.0

_________________________________

(1) Represents highest daily gross BOE rate.

(2) Represents gross average production for actual producing days through October 30, 2014.

(3) WOC - waiting on completion.

In the Mid-Continent, our net capital expenditures in the third quarter of 2014 totaled $42 million, resulting in current year to date total capital expenditures of $93.5million.

Appalachia

Net production from the Marcellus Shale area averaged 5.3 MBoe/d in the third quarter of 2014, compared to 7.2 MBoe/d for the third quarter of 2013 and 5.4 MBoe/d in the second quarter of 2014. Production volumes decreased due to natural production declines, partially offset by production contributions from the Simms U-5H well, our first Utica/Point Pleasant well that came on production in late August 2014,

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and the return to production of four gross Goudy Marcellus wells in July 2014 and three gross Simms Marcellus Shale wells in August 2014.

In the fourth quarter of 2014, we plan to complete ten gross (5.0 net) Marcellus Shale wells in Marshall County, West Virginia, with first production slated for late December 2014. Exiting 2014, we expect 67 total gross operated Marcellus Shale wells to be capable of production in the area.

Net capital expenditures in Appalachia for the third quarter of 2014 totaled $20 million, resulting in current year to date total capital expenditures of $39.5 million.

Liquidity

At September 30, 2014 we had $46.6 million in available cash and cash equivalentsand an undrawn $145.0 million borrowing base on our revolving credit facility. We expect to fund our remaining 2014 capital program through existing cash balances, internally generated cash flow from operating activities and borrowings under the revolving credit facility, or some combination thereof.

Revised 2015 Capital Budget

Gastar’s Board of Directors has recently elected to reduce its previously announced 2015 capital budget of approximately $257 million to approximately $173 million. The 33% decrease in the capital budget is a prudent action considering the recent decline in crude oil prices and the decline in realized natural gas prices in the Northeast. The reduced capital budget will allow Gastar to maintain a strong balance sheet and liquidity position during the current commodity price environment. The new budget consists of $138 million (previously $222 million) of drilling, completion and infrastructure costs, $28 million of land and seismic expenditures, and other capitalized costs of approximately $7 million. The revised capital budget should still result in significant year-over-year production growth as noted in our updated guidance below.

Gastar’s 2015 revised capital budget is expected to provide for 31 gross (15.4 net) (previously 44 gross (27.1 net)) wells in the Hunton Limestone play, three gross (1.5 net) (previously six gross (3.0 net)) wells in the Marcellus Shale play and one gross (0.5 net) (previously two gross (1.5 net)) well(s) in the Utica Shale play in addition to the postponement of two gross (1.5 net) Mid-Continent Stack Play wells and one gross (1.0 net) vertical well in Marcellus East. The focus of Gastar's 2015 Hunton Limestone play will be on acreage not currently held by production and the deferral of drilling expenditures on acreage held by production.

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Guidance for the Fourth Quarter of 2014 and Full Year 2015

We are updating previously issued guidance for full-years 2014 and 2015, and are providing the following guidance for the fourth quarter of 2014:

Production	Fourth Quarter 2014	Full-Year 2014	Full-Year 2015
Net average daily (MBoe/d)(1)	11.0 - 12.0	10.0 - 10.4	14.0 - 16.5
Liquids percentage	44% - 48%	44% - 48%	44% - 48%
Cash Operating Expenses	Fourth Quarter 2014	Full-Year 2014	Full-Year 2015
Production taxes (% of production revenues)	4.0% - 4.5%	4.0% - 4.5%	4.0% - 4.5%
Direct lease operating ($/Boe)	$4.50 - $5.00	$4.75 - $5.25	$4.25 - $4.75
Transportation, treating & gathering ($/Boe)	$0.45 - $0.55	$0.55 - $0.65	$0.45 - $0.55
Cash general & administrative ($/Boe)	$2.60 - $2.85	$3.00 - $3.30	$2.30 - $2.60

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(1) Based on equivalent of 6 Mcf of natural gas to one barrel of oil, condensate or NGLs.

Conference Call

Gastar has scheduled a conference call for 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on Friday, November 7, 2014.  Investors may participate in the call either by phone or audio webcast.

By Phone:	Dial 1-888-450-9962 at least 10 minutes before the call. A telephone replay will be available through November 14, 2014by dialing 1-800-804-7944 and using the conference ID 47755.
By Webcast:	Visit the Investor Relations page ofGastar'swebsite atwww.gastar.com under “Events & Presentations.” Please log on at least 10 minutes in advance to register and download any necessary software. A replay will be available shortly after the call.

For more information, please contact Donna Washburn at Dennard-Lascar Associates at 713-529-6600 or e-mail dwashburn@DennardLascar.com.

About Gastar Exploration

Gastar Exploration Inc. is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and natural gas liquids in the United States. Gastar’s

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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. In Oklahoma, Gastar is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal play and expects to test other prospective formations on the same acreage, including the Woodford Shale and the Meramec Shale (middle Mississippi Lime), which Gastar refers to as the Mid-Continent Stack Play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus Shale and has drilled its first successful dry gas Utica Shale/Point Pleasant well on its acreage. For more information, visit Gastar's website at www.gastar.com.

Forward Looking Statements

This news release includes “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward looking statements give our current expectations, opinion, belief or forecasts of future events and performance. A statement identified by the use of forward looking words including “may,” “expects,” “projects,” “anticipates,” “plans,” “believes,” “estimate,” “will,” “should,” and certain of the other foregoing statements may be deemed forward-looking statements. Although Gastar believes that the expectations reflected in such forward-looking statements are reasonable, these statements involve risks and uncertainties that may cause actual future activities and results to be materially different from those suggested or described in this news release. These include risks inherent in natural gas and oil drilling and production activities, including risks of fire, explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks, which may temporarily or permanently reduce production or cause initial production or test results to not be indicative of future well performance or delay the timing of sales or completion of drilling operations; delays in receipt of drilling permits; risks with respect to natural gas and oil prices, a material decline in which could cause Gastar to delay or suspend planned drilling operations or reduce production levels; risks relating to the availability of capital to fund drilling operations that can be adversely affected by adverse drilling results, production declines and declines in natural gas and oil prices; risks relating to unexpected adverse developments in the status of properties; borrowing base redeterminations by our banks; risks relating to the absence or delay in receipt of government approvals or fourth party consents; risks relating to our ability to integrate acquired assets with ours and to realize the anticipated benefits from such acquisitions; and other risks described in Gastar’s Annual Report on Form 10-K and other filings with the SEC, available at the SEC’s website at www.sec.gov. Our actual sales production rates can vary considerably from tested initial production rates depending upon completion and production techniques and our primary areas of operations are subject to natural steep decline rates. By issuing forward looking statements based on current expectations, opinions, views or

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beliefs, Gastar has no obligation and, except as required by law, is not undertaking any obligation, to update or revise these statements or provide any other information relating to such statements.

Unless otherwise stated herein, equivalent volumes of production and reserves are based upon an energy equivalent ratio of six Mcf of natural gas to each barrel of liquids (oil, condensate and NGLs), which ratio is not reflective of relative value. Our NGLs are sold as part of our wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from our wet gas production. Our reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which we are credited under our sales contracts.

Targeted expectations and guidance for 2015 are based upon the current revised 2015 capital expenditures budget, which may be subject to revision and reevaluation dependent upon future developments including drilling results, availability of crews, supplies and production capacity, weather delays, and significant changes in commodities prices or drilling costs.

- Financial Tables Follow -

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GASTAR EXPLORATION INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except share and per share data)
REVENUES:
Oil and condensate	$	22,793		$	9,381		$	61,913		$	22,731
Natural gas	7,151			10,099			40,129			30,113
NGLs	5,139			4,623			16,689			10,415
Total oil, condensate, natural gas and NGLs revenues	35,083			24,103			118,731			63,259
Gain (loss) on commodity derivatives contracts	6,663			(5,263		)	(8,761		)	(2,229		)
Total revenues	41,746			18,840			109,970			61,030
EXPENSES:
Production taxes	1,558			1,319			5,489			3,112
Lease operating expenses	4,136			2,190			13,057			6,196
Transportation, treating and gathering	397			1,098			3,168			3,386
Depreciation, depletion and amortization	11,111			8,467			33,773			21,428
Accretion of asset retirement obligation	129			142			376			358
General and administrative expense	4,002			3,998			12,658			11,964
Litigation settlement expense	—			—			—			1,000
Total expenses	21,333			17,214			68,521			47,444
INCOME FROM OPERATIONS	20,413			1,626			41,449			13,586
OTHER INCOME (EXPENSE):
Gain on acquisition of assets at fair value	—			—			—			43,712
Interest expense	(6,991		)	(3,439		)	(20,794		)	(7,593		)
Investment income and other	4			8			15			16
Foreign transaction loss	(1		)	(3		)	(7		)	(15		)
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES	13,425			(1,808		)	20,663			49,706
Provision for income taxes	—			—			—			—
NET INCOME (LOSS)	13,425			(1,808		)	20,663			49,706
Dividends on preferred stock	(3,618		)	(2,134		)	(10,805		)	(6,398		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	9,807		$	(3,942	)	$	9,858		$	43,308
NET INCOME (LOSS) PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic	$	0.16		$	(0.07	)	$	0.17		$	0.71
Diluted	$	0.15		$	(0.07	)	$	0.16		$	0.68
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic	60,006,903			57,359,357			58,982,709			61,159,117
Diluted	63,399,446			57,359,357			62,306,480			63,971,038

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GASTAR EXPLORATION INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2014			December 31, 2013
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	46,598		$	32,393
Accounts receivable, net of allowance for doubtful accounts of $0 and $507, respectively	21,859			21,656
Commodity derivative contracts	2,735			—
Prepaid expenses	1,842			1,145
Total current assets	73,034			55,194
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	119,368			96,220
Proved properties	1,048,756			935,773
Total oil and natural gas properties	1,168,124			1,031,993
Furniture and equipment	2,991			2,691
Total property, plant and equipment	1,171,115			1,034,684
Accumulated depreciation, depletion and amortization	(550,944		)	(517,171		)
Total property, plant and equipment, net	620,171			517,513
OTHER ASSETS:
Commodity derivative contracts	1,444			7,545
Deferred charges, net	2,785			2,950
Advances to operators and other assets	13,258			6,733
Total other assets	17,487			17,228
TOTAL ASSETS	$	710,692		$	589,935
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	18,266		$	11,046
Revenue payable	10,456			12,514
Accrued interest	10,512			3,504
Accrued drilling and operating costs	4,166			8,756
Advances from non-operators	11,681			9,259
Commodity derivative contracts	419			3,403
Commodity derivative premium payable	1,966			145
Asset retirement obligation	81			633
Other accrued liabilities	3,092			4,844
Total current liabilities	60,639			54,104
LONG-TERM LIABILITIES:
Long-term debt	314,704			312,994
Commodity derivative contracts	882			378
Commodity derivative premium payable	5,327			7,000
Asset retirement obligation	5,887			5,430
Total long-term liabilities	326,800			325,802
Commitments and contingencies
STOCKHOLDERS' EQUITY:
Preferred stock, 40,000,000 shares authorized
Series A Preferred stock, $0.01 par value; 10,000,000 shares authorized; 4,045,000 and 3,958,160 shares issued and outstanding at September 30, 2014 and December 31, 2013, respectively, with liquidation preference of $25.00 per share	41			40
Series B Preferred stock, $0.01 par value; 10,000,000 shares authorized; 2,140,000 shares issued and outstanding at September 30, 2014 and December 31, 2013, respectively, with liquidation preference of $25.00 per share	21			21
Common stock, $0.001 par value; 275,000,000 shares authorized; 78,862,165 and 61,211,658 shares issued and outstanding at September 30, 2014 and December 31, 2013, respectively	78			61
Additional paid-in capital	568,078			464,730
Accumulated deficit	(244,965		)	(254,823		)
Total stockholders' equity	323,253			210,029
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	710,692		$	589,935

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GASTAR EXPLORATION INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	20,663		$	49,706
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	33,773			21,428
Stock-based compensation	3,704			2,540
Mark to market of commodity derivatives contracts:
Total loss on commodity derivatives contracts	8,761			2,229
Cash settlements of matured commodity derivatives contracts, net	(7,705		)	5,929
Cash premiums paid for commodity derivatives contracts	(185		)	(102		)
Amortization of deferred financing costs	2,270			1,790
Accretion of asset retirement obligation	376			358
Settlement of asset retirement obligation	(580		)	—
Gain on acquisition of assets at fair value	—			(43,712		)
Changes in operating assets and liabilities:
Accounts receivable	(4,242		)	(1,549		)
Prepaid expenses	(697		)	481
Accounts payable and accrued liabilities	4,143			141
Net cash provided by operating activities	60,281			39,239
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties	(100,818		)	(77,813		)
Advances to operators	(43,337		)	(13,104		)
Acquisition of oil and natural gas properties - refund (expenditure)	4,209			(78,809		)
Proceeds from sale of oil and natural gas properties	3,077			70,708
Proceeds from (payments to) non-operators	2,422			(4,589		)
Purchase of furniture and equipment	(300		)	(484		)
Net cash used in investing activities	(134,747		)	(104,091		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	58,000			19,000
Repayment of revolving credit facility	(58,000		)	(117,000		)
Proceeds from issuance of senior secured notes, net of discount	—			194,500
Proceeds from issuance of common stock, net of issuance costs	101,513			—
Repurchase of outstanding common stock	—			(9,753		)
Proceeds from issuance of preferred stock, net of issuance costs	2,064			133
Dividends on preferred stock	(10,805		)	(6,398		)
Deferred financing charges	(405		)	(2,807		)
Tax withholding related to restricted stock and PBU vestings	(3,709		)	(349		)
Other	13			—
Net cash provided by financing activities	88,671			77,326
NET INCREASE IN CASH AND CASH EQUIVALENTS	14,205			12,474
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	32,393			8,901
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	46,598		$	21,375

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NON-GAAP FINANCIAL INFORMATION AND RECONCILIATION

We use both GAAP and certain non-GAAP financial measures to assess performance. Generally, a non-GAAP financial measure is a numerical measure of a company’s performance, financial position or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with GAAP. Our management believes that these non-GAAP measures provide useful supplemental information to investors in order that they may evaluate our financial performance using the same measures as management. These non-GAAP financial measures should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP. In evaluating these measures, investors should consider that the methodology applied in calculating such measures may differ among companies and analysts. A reconciliation is provided below outlining the differences between these non-GAAP measures and their most directly comparable financial measure calculated in accordance with GAAP.

Reconciliation of Net Income (Loss) to Net Income Excluding Special Items:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014		2013
	(in thousands, except share and per share data)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED (1)	$	9,807		$	(3,942	)	$	9,858	$	43,308
SPECIAL ITEMS:
(Gains) losses related to the change in mark to market value for outstanding commodity derivatives contracts	(7,623		)	5,004			950		7,156
Non-recurring general and administrative costs related to acquisition of assets	—			292			30		1,710
Non-recurring general and administrative costs related to Parent migration	15			321			233		590
Non-recurring severance costs related to property divestment	—			659			—		659
Non-recurring stock compensation benefit related to property divestment	—			(422		)	—		(422		)
Litigation settlement expense	—			—			—		1,000
Gain on acquisition of assets at fair value	—			—			—		(43,712		)
Write off of fees associated with old amended revolving credit facility	—			—			—		1,154
Foreign transaction loss	1			3			7		15
ADJUSTED NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	2,200		$	1,915		$	11,078	$	11,458
ADJUSTED NET INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic	$	0.04		$	0.03		$	0.19	$	0.19
Diluted	$	0.03		$	0.03		$	0.18	$	0.18
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic	60,006,903			57,359,357			58,982,709		61,159,117
Diluted	63,399,446			60,997,747			62,306,480		63,971,038

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⁽¹⁾  The nine months ended September 30, 2014 includes the benefit of an $8.6 million one-time adjustment related to an arbitration settlement.

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Reconciliation of Cash Flows before Working Capital Changes and as Adjusted for Special Items:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) (1)	$	13,425		$	(1,808	)	$	20,663		$	49,706
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	11,111			8,467			33,773			21,428
Stock-based compensation	1,172			574			3,704			2,540
Mark to market of commodity derivatives contracts:
Total loss (gain) on commodity derivatives contracts	(6,663		)	5,263			8,761			2,229
Cash settlements of matured commodity derivatives contracts, net	(1,644		)	333			(7,705		)	5,929
Cash premiums paid for commodity derivatives contracts	(30		)	(75		)	(185		)	(102		)
Amortization of deferred financing costs	779			340			2,270			1,790
Accretion of asset retirement obligation	129			142			376			358
Settlement of asset retirement obligation	(34		)	—			(580		)	—
Gain on acquisition of assets at fair value	—						—			(43,712		)
Cash flows from operations before working capital changes	18,245			13,236			61,077			40,166
Litigation settlement expense	—			—			—			1,000
Foreign transaction loss	1			3			7			15
Dividends on preferred stock	(3,618		)	(2,134		)	(10,805		)	(6,398		)
Non-recurring general and administrative costs related to acquisition of assets	—			292			30			1,710
Non-recurring severance costs related to property divestment	—			659			—			659
Non-recurring general and administrative costs related to Parent migration	15			321			233			590
Adjusted cash flows from operations	$	14,643		$	12,377		$	50,542		$	37,742

_________________________________

⁽¹⁾  The nine months ended September 30, 2014 includes the benefit of an $8.6 million one-time adjustment related to an arbitration settlement.

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Reconciliation of Net Income (Loss) to Adjusted Earnings Before Interest, Income Taxes, Depreciation, Depletion and Amortization ("Adjusted EBITDA"):

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except share and per share data)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED (1)	$	9,807		$	(3,942	)	$	9,858		$	43,308
Interest expense	6,991			3,439			20,794			7,593
Depreciation, depletion and amortization	11,111			8,467			33,773			21,428
EBITDA	27,909			7,964			64,425			72,329
Dividend expense	3,618			2,134			10,805			6,398
Accretion of asset retirement obligation	129			142			376			358
Gain on acquisition of assets at fair value	—			—			—			(43,712		)
(Gains) losses related to the change in mark to market value for outstanding commodity derivatives contracts	(7,623		)	5,004			950			7,156
Non-cash stock compensation expense	1,172			574			3,704			2,540
Litigation settlement expense	—			—			—			1,000
Foreign transaction loss	1			3			7			15
Investment income and other	(4		)	(8		)	(15		)	(16		)
Non-recurring general and administrative costs related to acquisition of assets	—			292			30			1,710
Non-recurring general and administrative costs related to Parent migration	15			321			233			590
Non-recurring severance costs related to property divestment	—			659			—			659
Adjusted EBITDA	$	25,217		$	17,085		$	80,515		$	49,027

_________________________________

⁽¹⁾  The nine months ended September 30, 2014 includes the benefit of an $8.6 million one-time adjustment related to an arbitration settlement.

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