Gastar Exploration (GST) 8-K Fourth Quarter and Full-year 2014 Results

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 ANNOUNCES

FOURTH QUARTER AND FULL-YEAR 2014 RESULTS

• Year-end Reserves Total 102 Million Boe

• Fourth Quarter Production Increased 27% Year-Over-Year to 11.7 MBoe/d

• Borrowing Base Increased to $200 Million with $145 Million Available

HOUSTON, March 12, 2015 - Gastar Exploration Inc. (NYSE MKT: GST) (“Gastar”) today reported financial and operating results for the three and twelve months ended December 31, 2014.

Net income attributable to Gastar’s common stockholders for the fourth quarter of 2014 was $26.7million, or $0.34 per diluted share. Excluding the impact of a $24.9 million gain resulting from the mark-to-market of outstanding hedge positions, adjusted net income attributable to common stockholders was $1.8 million, or $0.02 per diluted share. This compares to a fourth quarter 2013 reported net loss of $3.3 million, or a loss of $0.06 per diluted share, and fourth quarter 2013 adjusted net income of $698,000, or $0.01 per diluted share, excluding the impact of a $2.8 million loss resulting from the mark-to-market of outstanding hedge positions, $639,000 of acquisition costs and non-recurring corporate restructuring charges of $593,000. (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 fourth quarter of 2014 was $25.9 million, an increase of 22% compared to $21.2 million for the fourth quarter of 2013. (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 13% to $33.1 million in the fourth quarter of 2014 from $29.2 million in the fourth quarter of 2013, but declined 6% from revenues of $35.1 million in the third quarter of 2014. The increase in oil, condensate, natural gas and NGLs revenues from fourth quarter of 2013 to fourth quarter of 2014 was primarily the result of a 27% increase in production offset by an 11% decrease in weighted average

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realized equivalent prices. The decrease from third quarter of 2014 revenues was due to a 21% decline in equivalent product pricing offset by a 19% increase in equivalent production volumes.

Revenues from liquids (oil, condensate and NGLs) represented approximately 77% of total production revenues in the fourth quarter of 2014, compared to 65% for the fourth quarter of 2013 and 80%during the third quarter of 2014. We had hedges in place covering approximately 76% of our natural gas production, 36% of our oil and condensate production and 65% of our NGLs production for the fourth quarter of 2014. Commodity derivative contracts settled during the period resulted in a $3.5 million increase in revenue for the fourth quarter of 2014, compared to a $288,000 increase in revenue for the fourth quarter of 2013 and a $960,000 reduction in revenue for the third 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 fourth quarter of 2014 was 11,700 barrels of oil equivalent per day (“Boe/d”) (on a 6:1 gas (Mcf) to liquids (barrel) equivalent basis) as compared to 9,200 Boe/d in the fourth quarter of 2013 and 9,800 Boe/d in the third quarter of 2014. Oil, condensate and NGLs as a percentage of production volumes were 53% in the fourth quarter of 2014 compared to 39% in the fourth quarter of 2013 and 48% in the third quarter of 2014.

J. Russell Porter, Gastar's President and CEO, commented, “Gastar ended 2014 on a very positive note and we are well positioned to execute our business plan in 2015. We have ample liquidity and are off to a very encouraging start in 2015 with additional excellent drilling results on our West Edmond Hunton Lime Unit (“WEHLU”) acreage. In 2014, we strengthened our balance sheet with an equity issuance and continued our track-record of growing our reserve base to support a larger credit facility, which now includes an additional $55 million of borrowing capacity under the revolver. In addition to achieving reserve growth of 87% in 2014, we also continued to meet our strategic objective of increasing our weighting towards liquids, which now represents 53% of our reserve base, of which 29% is oil and 24% is NGLs.”

“We are taking a conservative approach to our 2015 capital budget, which as previously announced was reduced to approximately $103 million, since we believe maintaining liquidity and financial discipline will benefit us in these uncertain market conditions. Despite a significantly lower capital budget in 2015 compared to 2014, we anticipate our production for 2015 will grow by approximately 22% compared to 2014 production (based on mid-point guidance).”

“We are investing our capital in areas that will generate acceptable returns while also positioning us for improved liquidity through new proven reserve additions. In the Mid-Continent, the Hunton formation continues to represent a substantial source of high return projects. Our 2015 Hunton drilling program will focus on our WEHLU acreage. We have seen oil production rates from wells in our WEHLU acreage

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that exceed our type curves, and when combined with the lower cost structure associated with the projects, we can achieve strong economic returns in the current price environment. We are encouraged by the early production results of our most recent upper and lower Hunton wells in the southern portion of our WEHLU acreage. In the Appalachian Basin, we have limited near-term lease expirations, allowing us to postpone any new drilling and wait for better natural gas and NGLs pricing to improve economic returns in the region.”

The following table provides a summary of Gastar’s production volumes and average commodity prices for the three and twelve months ended December 31, 2014 and 2013:

	For the Three Months Ended December 31,				For the Years Ended December 31,
	2014		2013		2014		2013
Production:
Oil and condensate (MBbl)	315		182		975		515
Natural gas (MMcf)	3,019		3,108		11,598		13,366
NGLs (MBbl)	258		147		801		494
Total production (MBoe)	1,076		847		3,708		3,236
Daily Production:
Oil and condensate (MBbl/d)	3.4		2.0		2.7		1.4
Natural gas (MMcf/d)	32.8		33.8		31.8		36.6
NGLs (MBbl/d)	2.8		1.6		2.2		1.4
Total daily production (MBoe/d)	11.7		9.2		10.2		8.9
Average sales price per unit(1):
Oil and condensate per Bbl, including impact of hedging(2)	$	70.48	$	75.62	$	80.63	$	71.04
Oil and condensate per Bbl, excluding impact of hedging	$	66.43	$	75.75	$	81.75	$	70.91
Natural gas per Mcf, including impact of hedging(2)	$	2.57	$	3.58	$	3.14	$	3.43
Natural gas per Mcf, excluding impact of hedging	$	2.49	$	3.31	$	3.41	$	3.02
NGLs per Bbl, including impact of hedging(2)	$	25.86	$	31.93	$	27.37	$	31.13
NGLs per Bbl, excluding impact of hedging	$	18.21	$	35.34	$	27.55	$	31.59
Average sales price per Boe, including impact of hedging(2)	$	34.02	$	34.89	$	36.92	$	30.20
Average sales price per Boe, excluding impact of hedging	$	30.79	$	34.55	$	38.09	$	28.58

_____________________________

(1) The twelve months ended December 31, 2014 average sales price per unit excludes 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.

Lease operating expenses (“LOE”) were $6.3 million for the fourth quarter of 2014, compared to $3.3 million in the fourth quarter of 2013 and $4.1 million in the third quarter of 2014. The increase in LOE compared to the fourth quarter of 2013 was primarily due to increased expenses from new wells drilled and acquired in mid-to-late 2013 combined with higher overall costs associated with producing oil versus natural gas. Compared to the third quarter of 2014, LOE in the fourth quarter of 2014 included increased workover costs of $608,000 for one-time operations on five wells on our operated WEHLU acreage as

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well as higher frack water disposal costs associated with bringing new wells online. LOE per barrel of oil equivalent (“Boe”) of production was $5.83 in the fourth quarter of 2014 versus $3.85 in the fourth quarter of 2013 and $4.59 in the third quarter of 2014.

Depreciation, depletion and amortization expense (“DD&A”) was $12.4 million in the fourth quarter of 2014, up from $11.0 million in the fourth quarter of 2013 and $11.1 million in the third quarter of 2014. The increase in DD&A expense is the result of higher production volumes in the fourth quarter of 2014. The DD&A rate for the fourth quarter of 2014 was $11.53 per Boe compared to $13.02 per Boe for the fourth quarter of 2013 and $12.33 per Boe in the third quarter of 2014. The lower DD&A rate per Boe is due to the increase in year-end proved reserves.

General and administrative (“G&A”) expense was $3.8 million in the fourth quarter of 2014 compared to $5.0 million in the fourth quarter of 2013 and $4.0 million in the third quarter of 2014. G&A expense for the fourth quarter of 2014 included $1.2 million of non-cash, stock-based compensation expense, versus $895,000 in the fourth quarter of 2013 and $1.2 million in the third quarter of 2014. Excluding stock compensation expense, cash G&A expense decreased to $2.6 million in the fourth quarter of 2014 from $4.1 million in the fourth quarter of 2013 and $2.8 million in the third quarter of 2014. The decrease from the fourth quarter of 2013 was primarily due to a reduction in acquisition-related costs, lower costs associated with reorganization to eliminate Gastar’s holding company corporate structure and fourth quarter 2013 severance costs related to property divestments, partially offset by the current year’s higher legal costs and higher personnel costs related to property acquisitions.

Interest expense totaled $6.8 million in the fourth quarter of 2014, compared to $5.6 million in the fourth 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.

Operations Review and Update

Mid-Continent

Net production from the Mid-Continent area increased to an average of 5,600 Boe/d in the fourth quarter of 2014, compared to 2,300 Boe/d in the fourth quarter of 2013 and 4,500 Boe/d in the third quarter of 2014. Fourth quarter 2014 Mid-Continent production consisted of approximately 54% oil, 27% natural gas and 19% NGLs.

Currently, there are no rigs drilling on our AMI joint venture acreage. Along with our AMI partner, we continue to monitor oil prices and service costs and will re-evaluate resuming our drilling program later in the year based on market conditions.

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Within our AMI acreage, seven gross (3.2 net) non-operated wells were placed on production during the fourth quarter of 2014. We expect to complete and bring on production four gross (2.1 net) wells in the first quarter of 2015 and six gross (2.4 net) wells in the second quarter of 2015. To date in 2015, two gross (0.9 net) non-operated wells have been placed on production and eight gross (3.6 net) non-operated wells have been drilled and are awaiting completion.

The table below shows wells brought on production or for which drilling operations have commenced since the beginning of the fourth 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	Approximate Gross Costs to Drill & Complete ($ millions)
Shimanek 1-2H	48.9%	5,000	1,829	887	64%	October 9, 2014	$6.0
Hobbs Ranch 1-19H	47.0%	4,400	875	556	77%	October 13, 2014	$5.2
Snowman 1-19H	48.9%	4,900	295	188	72%	October 19, 2014	$5.6
Breckenridge 1-2H	25.4%	4,800	207	143	76%	November 7, 2014	$5.0
Bear Claw 1-28H	50.0%	5,000	395	296	70%	November 13,2014	$6.2
Joyce 1-10H(3)	51.7%	5,300	904	519	74%	December 5, 2014	$6.9
Barry 1-6H	47.8%	5,000	427	307	85%	December 13, 2014	$6.0
LB 1-1H	50.0%	4,400	N/A	N/A	N/A	January 23, 2015	$5.0
Boss Hogg 1-14H	42.0%	4,400	N/A	68	60%	February 21, 2015	$7.2
Polar Bear 1-20H	47.6%	4,400	N/A	N/A	N/A	Awaiting completion	$5.0
Falcon 1-5H	51.5%	4,700	N/A	N/A	N/A	Awaiting completion	$5.0
The River 1-22H	28.3%	4,400	N/A	N/A	N/A	Awaiting completion	$5.0
Hubbard 1-23H(4)	57.0%	4,600	N/A	N/A	N/A	Awaiting completion	$5.0
Bigfoot 1-9H	43.0%	4,800	N/A	N/A	N/A	Awaiting completion	$5.0
Bo 1-23H	50.0%	4,900	N/A	N/A	N/A	Awaiting completion	$5.0
Dorothy 1-12H	31.0%	5,000	N/A	N/A	N/A	Awaiting completion	$5.0
Unruh 1-34H	50.0%	4,900	N/A	N/A	N/A	Awaiting completion	$5.0

_____________________________

(1) Represents highest daily gross Boe rate.

(2) Represents gross average production for actual producing days through February 28, 2015.

(3) After payout working interest is 45.0%.

(4) After payout working interest is 49.9%.

During the fourth quarter of 2014, we completed two gross (2.0 net) operated horizontal wells, the Deer Draw 21-4H and Deer Draw 21-5H, both located on the northern portion of our WEHLU acreage. To date in 2015, two gross (2.0 net) operated horizontal wells, the Warsaw 33-2H, an upper Hunton completion, and the Warsaw 33-3H, a lower Hunton completion, both located on the southern portion of our WEHLU acreage, were placed on production. Early production results from all four wells are exceeding our type curve production projections.

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The table below shows wells brought on production or for which drilling operations have commenced since the beginning of the fourth 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	Approximate Gross Costs to Drill & Complete ($ millions)
Deer Draw 21-4H	98.3%	5,900	495	413	81%	November 7, 2014	$4.9
Deer Draw 21-5H	98.3%	4,900	344	234	85%	November 9, 2014	$5.0
Warsaw 33-2H	98.3%	4,900	N/A	481	80%	February 12, 2015	$3.5
Warsaw 33-3H	98.3%	5,800	648	277	71%	February 13, 2015	$5.9
Warsaw 33-1(3)	98.3%	N/A	N/A	N/A	N/A	Awaiting completion	$3.5
Easton 22-3H	98.3%	6,500	N/A	N/A	N/A	Drilling	$5.0
Blair Farms 31-1H	98.3%	6,500	N/A	N/A	N/A	Drilling	$3.2

_____________________________

(1) Represents highest daily gross Boe rate.

(2) Represents gross average production for actual producing days through February 28, 2015.

(3) The Warsaw 33-1 is a vertical well.

We currently have two rigs running on the northern portion of our WEHLU acreage drilling the Easton 22-3H, a lower Hunton well, and the Blair Farms 31-1H, an upper Hunton well. These wells are currently scheduled to be on production during the second quarter of 2015. Once drilling is complete on these two wells, we plan to move a rig to the southern portion of our WEHLU acreage to drill areas that presently do not contain any proven or probable reserves.

In the Mid-Continent, our net capital expenditures in the fourth quarter of 2014 totaled $47 million, resulting in full year 2014 total capital expenditures of $141million. Our 2015 capital expenditure budget in the Mid-Continent is $69 million, of which $60 million is allocated to drilling and completion and $9 million to lease extensions.

Appalachian Basin

Net production from the Appalachian Basin area averaged 6,100 Boe/d in the fourth quarter of 2014, compared to 6,800 Boe/d for the fourth quarter of 2013 and 5,300 Boe/d in the third quarter of 2014. Year-over-year production volumes decreased due to natural production declines and fewer wells being brought on production. The sequential increase was due to seven gross (3.5 net) Armstrong Marcellus Shale wells and three gross (1.5 net) Hansen Marcellus Shale wells being brought on production in mid-to-late December 2014. The Armstrong pad seven well gross initial production rate was approximately 13,800 Mcf/d and 2,300 barrels of condensate per day. The Hansen pad three well gross initial production rate was approximately 11,400 Mcf/d and 1,500 barrels of condensate per day.

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In February 2015, we completed the three gross (1.5 net) remaining Marcellus Shale wells on the Goudy pad and have recently commenced flow back operations. Gross initial production from the three recent Goudy well completions was approximately 5,300 Mcf/d and 890 barrels of condensate per day. Currently, we are completing two gross (1.0 net) Marcellus Shale wells on the Hoyt pad and are planning to complete two gross (1.0 net) Marcellus Shale wells and one gross (0.5 net) Utica/Point Pleasant well on the Blake pad. Production is scheduled to commence on the Hoyt pad in April 2015 followed by production on the Blake pad in May 2015.

Net capital expenditures in the Appalachian Basin for the fourth quarter of 2014 totaled $36 million, resulting in full year 2014 total capital expenditures of $76 million. We have allocated approximately $27 million of our 2015 capital budget to the Appalachian Basin, of which $19 million is for the completion of eight gross (4.0 net) previously drilled wells and $8 million is primarily for acquiring additional mineral rights in the area. We will continue to monitor commodity prices and services costs in the area and may elect to resume drilling should economic conditions warrant.

Liquidity

At December 31, 2014 we had approximately $11 million in available cash and cash equivalentsand $100 million of availability under our $145 million revolving credit facility. Effective March 9, 2015, we increased the borrowing base on our revolving credit facility to $200 million with $55 million of borrowings outstanding. We expect to fund our 2015 capital program through existing cash balances, internally generated cash flow from operating activities, borrowings under the revolving credit facility, and potential property sales or some combination thereof.

Guidance for the First Quarter of 2015

We are reiterating our previously issued guidance for the full year 2015 and providing the following guidance for the first quarter of 2015:

Production	First Quarter 2015	Full-Year 2015
Net average daily (MBoe/d)(1)	11.8 - 12.2	11.5 - 13.4
Liquids percentage	53% - 56%	54% - 58%
Cash Operating Expenses ($ / Boe)	First Quarter 2015	Full-Year 2015
Production taxes (% of production revenues)	3.8% - 4.1%	3.8% - 4.3%
Direct lease operating ($/Boe)	$5.50 - $5.80	$5.00 - $5.60
Transportation, treating & gathering ($/Boe)	$0.35 - $0.45	$0.35 - $0.45
Cash general & administrative ($/Boe)	$2.70 - $3.00	$2.70 - $3.00

________________

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

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2014 Proved Reserves

As previously reported, proved reserves as of December 31, 2014 increased by 87% to 102.1 million barrels of oil equivalent (“MMBoe”), composed of 28.6 million barrels of crude oil and condensate, 25.6 million barrels of natural gas liquids and 287 billion cubic feet of natural gas. Of the total proved reserves, 36% are classified as proved developed. The pre-tax SEC-priced present value of future cash flows of these reserves, discounted at 10% (“PV-10”) (a non-GAAP financial measure defined below in Information on Reserves and PV-10 Value), grew 67% to $988.7 million as compared to year-end 2013.

The year-over-year net increase in proved reserves of 47.4 MMBoe primarily consisted of 42.8 MMBoe of proved reserve additions (pre-tax PV-10 value of $369.8 million).

Capital expenditures for 2014 totaled $220.5 million, comprised of $36.7 million for unproved acreage and related costs and $183.8 million for drilling expenditures.

Conference Call

Gastar has scheduled a conference call for 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on Friday, March 13, 2015.  Investors may participate in the call either by phone or audio webcast.

By Phone:	Dial 1-412-902-0030 at least 10 minutes before the call. A telephone replay will be available through March 20 by dialing 1-201-612-7415 and using the conference ID: 13600505.
By Webcast:	Visit the Investor Relations page of Gastar's website at www.gastar.com under “Events & Presentations.” Please log on a few 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 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 in the future plans 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 Stack Play. In West Virginia, Gastar is developing liquids-rich natural

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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.

Information on Reserves and PV-10 Value

For the years ended December 31, 2014 and 2013, 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”). Benchmark base prices are held constant in accordance with SEC guidelines for the life of the wells 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 $94.99 per barrel WTI spot oil price and the Henry Hub natural gas price of $4.35 per MMBtu average benchmark base prices used in our December 31, 2014 SEC compliant reserves report are significantly above current market commodity prices.

PV-10 is a non-GAAP financial measure as defined by the SEC because it excludes the effects of income taxes. We believe that the presentation of PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our reserves prior to taking into account corporate future income taxes and our current tax structure. We further believe investors and creditors use PV-10 as a basis for comparison of the relative size of our reserves as compared with other companies.

The financial measure most directly comparable to PV-10 is the standardized measure of future net cash flows (“Standardized Measure”). Our PV-10 as of December 31, 2014 of $988.7 million differs from our Standardized Measure of $816.7 million as of such date because Standardized Measure is reduced by the discounted effect of estimated future income taxes, which discounted at 10% were $172.0 million.

We use the term “EUR” or “estimated ultimate recovery” to describe potentially recoverable oil and gas hydrocarbon quantities that are not permitted to be used in filings with the SEC. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial capital spending over a significant number of years to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. In addition, we have made no commitment to drill, and likely will not drill, all of the drilling locations which have been attributed to these quantities.

Ultimate recoveries will be dependent on numerous factors, including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of

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capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases.

The Company’s 2014 year-end total proved reserves estimates were prepared by Wright & Company, Inc.

Forward Looking Statements

This news release also 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 with respect to continued low or further declining prices for oil and natural gas that could cause Gastar to further delay or suspend planned drilling and completion operations or reduce production levels which would adversely impact cash flow; 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 regarding our ability to meet financial covenants under our indenture or credit agreements or the ability to obtain amendments or waivers to effect such compliance; 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 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 third-party consents; risks relating to our ability to realize the anticipated benefits from acquired assets; 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 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.

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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

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Three Months Ended December 31,						For the Years Ended December 31,
	2014			2013			2014			2013
	(in thousands, except share and per share data)
REVENUES:
Oil and condensate	$	20,907		$	13,749		$	82,820		$	36,480
Natural gas	7,518			10,303			47,647			40,416
NGLs	4,693			5,196			21,382			15,611
Total oil and condensate, natural gas and NGLs revenues	33,118			29,248			151,849			92,507
Gain (loss) on commodity derivatives contracts	28,330			(2,523		)	19,569			(4,752		)
Total revenues	61,448			26,725			171,418			87,755
EXPENSES:
Production taxes	1,244			1,539			6,733			4,651
Lease operating expenses	6,266			3,260			19,323			9,456
Transportation, treating and gathering	511			620			3,679			4,006
Depreciation, depletion and amortization	12,407			11,021			46,180			32,449
Accretion of asset retirement obligation	130			110			506			468
General and administrative expense	3,827			4,997			16,485			16,961
Litigation settlement expense	—			—			—			1,000
Total expenses	24,385			21,547			92,906			68,991
INCOME FROM OPERATIONS	37,063			5,178			78,512			18,764
OTHER INCOME (EXPENSE):
(Loss) gain on acquisition of assets at fair value	—			(16,042		)	—			27,670
Interest expense	(6,777		)	(5,575		)	(27,571		)	(13,168		)
Investment income and other	4			32			19			48
Foreign transaction gain (loss)	—			1			(7		)	(14		)
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES	30,290			(16,406		)	50,953			33,300
Income tax benefit	—			(16,042		)	—			(16,042		)
NET INCOME (LOSS)	30,290			(364		)	50,953			49,342
Dividends on preferred stock	(3,619		)	(2,980		)	(14,424		)	(9,378		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	26,671		$	(3,344	)	$	36,529		$	39,964
NET INCOME (LOSS) PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic	$	0.35		$	(0.06	)	$	0.58		$	0.66
Diluted	$	0.34		$	(0.06	)	$	0.55		$	0.63
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic	75,994,979			57,433,550			63,270,733			60,220,115
Diluted	78,577,762			57,433,550			66,492,589			63,618,401

12

GASTAR EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2014			2013
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,008		$	32,393
Accounts receivable, net of allowance for doubtful accounts of $0 and $507, respectively	30,841			21,656
Commodity derivative contracts	19,687			—
Prepaid expenses	2,083			1,145
Total current assets	63,619			55,194
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	128,274			96,220
Proved properties	1,124,367			935,773
Total natural gas and oil properties	1,252,641			1,031,993
Furniture and equipment	3,010			2,691
Total property, plant and equipment	1,255,651			1,034,684
Accumulated depreciation, depletion and amortization	(563,351		)	(517,171		)
Total property, plant and equipment, net	692,300			517,513
OTHER ASSETS:
Commodity derivative contracts	7,815			7,545
Deferred charges, net	2,586			2,950
Advances to operators and other assets	9,474			6,733
Total other assets	19,875			17,228
TOTAL ASSETS	$	775,794		$	589,935
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	28,843		$	11,046
Revenue payable	9,122			12,514
Accrued interest	3,528			3,504
Accrued drilling and operating costs	5,977			8,756
Advances from non-operators	1,820			9,259
Commodity derivative contracts	—			3,403
Commodity derivative premium payable	2,481			145
Asset retirement obligation	82			633
Other accrued liabilities	3,175			4,844
Total current liabilities	55,028			54,104
LONG-TERM LIABILITIES:
Long-term debt	360,303			312,994
Commodity derivative contracts	—			378
Commodity derivative premium payable	4,702			7,000
Asset retirement obligation	5,475			5,430
Total long-term liabilities	370,480			325,802
Commitments and contingencies
STOCKHOLDERS' EQUITY:
Preferred stock, 40,000,000 shares authorized
Series A Preferred stock, par value $0.01 per share; 10,000,000 shares authorized; 4,045,000 and 3,958,160 shares issued and outstanding at December 31, 2014 and 2013, respectively, with liquidation preference of $25.00 per share	41			40
Series B Preferred stock, par value $0.01 per share; 10,000,000 shares authorized; 2,140,000 shares issued and outstanding at December 31, 2014 and 2013, respectively, with liquidation preference of $25.00 per share	21			21
Common stock, par value $0.001 per share; 275,000,000 shares authorized; 78,632,810 and 61,211,658 shares issued and outstanding at December 31, 2014 and 2013, respectively	78			61
Additional paid-in capital	568,440			464,730
Accumulated deficit	(218,294		)	(254,823		)
Total stockholders' equity	350,286			210,029
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	775,794		$	589,935

13

GASTAR EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the years ended December 31,
	2014			2013			2012
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	50,953		$	49,342		$	(153,791	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	46,180			32,449			25,424
Impairment of natural gas and oil properties	—			—			150,787
Stock-based compensation	4,890			3,435			3,295
Mark to market of commodity derivatives contracts:
Total (gain) loss on commodity derivatives contracts	(19,569		)	4,752			(7,422		)
Cash settlements of matured commodity derivative contracts, net	(4,901		)	5,892			16,251
Cash premiums paid for commodity derivatives contracts	(185		)	(152		)	(4,539		)
Amortization of deferred financing costs	3,067			2,322			224
Accretion of asset retirement obligation	506			468			388
Settlement of asset retirement obligation	(588		)	(66		)	(636		)
Gain on acquisition of assets at fair value	—			(27,670		)	—
Deferred tax benefit	—			(16,042		)	—
Changes in operating assets and liabilities:
Accounts receivable	(12,524		)	(8,431		)	2,487
Prepaid expenses	(938		)	(48		)	146
Accounts payable and accrued liabilities	(2,566		)	1,563			4,441
Net cash provided by operating activities	64,325			47,814			37,055
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties	(155,631		)	(95,343		)	(136,311		)
Advances to operators	(61,067		)	(22,213		)	(9,649		)
Acquisition of oil and natural gas properties - refund (expenditure)	4,209			(251,096		)	—
Proceeds from sale of oil and natural gas properties	5,530			112,201			—
Use of proceeds from non-operators	(7,439		)	(8,281		)	(1,983		)
Purchase of furniture and equipment	(319		)	(766		)	(296		)
Net cash used in investing activities	(214,717		)	(265,498		)	(148,239		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common shares, net of issuance costs	101,319			—			—
Repurchase of common stock	—			(9,753		)	—
Proceeds from revolving credit facility	103,000			19,000			98,000
Repayment of revolving credit facility	(58,000		)	(117,000		)	(30,000		)
Proceeds from issuance of senior secured notes, net of discount	—			312,279			—
Proceeds from issuance of preferred stock, net of issuance costs	2,064			50,183			49,250
Dividends on preferred stock	(14,424		)	(9,378		)	(7,077		)
Deferred financing charges	(405		)	(3,785		)	(450		)
Tax withholding related to restricted stock and PBU vestings	(4,562		)	(334		)	(336		)
Other	15			(36		)	51
Net cash provided by financing activities	129,007			241,176			109,438
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(21,385		)	23,492			(1,746		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	32,393			8,901			10,647
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	11,008		$	32,393		$	8,901

14

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 December 31,						For the Years Ended December 31,
	2014			2013			2014			2013
	(in thousands, except share and per share data)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED (1)	$	26,671		$	(3,344	)	$	36,529		$	39,964
SPECIAL ITEMS:
(Gains) losses related to the change in mark to market value for outstanding commodity derivatives contracts	(24,852		)	2,811			(23,902		)	9,967
Non-recurring general and administrative costs related to acquisition of assets	—			639			30			2,349
Non-recurring general and administrative costs related to Parent migration				593			233			1,183
Non-recurring severance costs related to property divestment	—			—			—			659
Non-recurring stock compensation benefit related to property divestment	—			—			—			(422		)
Litigation settlement expense	—			—			—			1,000
Loss (gain) on acquisition of assets at fair value	—			16,042			—			(27,670		)
Write off of fees associated with old amended revolving credit facility	—			—			—			1,154
Foreign transaction loss	—			(1		)	7			14
Income tax benefit	—			(16,042		)	—			(16,042		)
ADJUSTED NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	1,819		$	698		$	12,897		$	12,156
ADJUSTED NET INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic	$	0.02		$	0.01		$	0.20		$	0.20
Diluted	$	0.02		$	0.01		$	0.19		$	0.19
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic	75,994,979			57,433,550			63,270,733			60,220,115
Diluted	78,577,762			61,248,076			66,492,589			63,618,401

_________________________________

⁽¹⁾  The year ended December 31, 2014 includes the benefit of an $8.6 million non-recurring 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 December 31,						For the Years Ended December 31,
	2014			2013			2014			2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) (1)	$	30,290		$	(364	)	$	50,953		$	49,342
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	12,407			11,021			46,180			32,449
Stock-based compensation	1,186			895			4,890			3,435
Mark to market of commodity derivatives contracts:
Total (gain) loss on commodity derivatives contracts	(28,330		)	2,523			(19,569		)	4,752
Cash settlements of matured commodity derivatives contracts, net	2,804			(37		)	(4,901		)	5,892
Cash premiums paid for commodity derivatives contracts	—			(50		)	(185		)	(152		)
Amortization of deferred financing costs	797			532			3,067			2,322
Accretion of asset retirement obligation	130			110			506			468
Settlement of asset retirement obligation	(8		)	(66		)	(588		)	(66		)
Gain on acquisition of assets at fair value	—			16,042			—			(27,670		)
Income tax benefit	—			(16,042		)	—			(16,042		)
Cash flows from operations before working capital changes	19,276			14,564			80,353			54,730
Litigation settlement expense	—			—			—			1,000
Foreign transaction loss (gain)	—			(1		)	7			14
Dividends on preferred stock	(3,619		)	(2,980		)	(14,424		)	(9,378		)
Non-recurring general and administrative costs related to acquisition of assets	—			639			30			2,349
Non-recurring severance costs related to property divestment	—			—			—			659
Non-recurring general and administrative costs related to Parent migration	—			593			233			1,183
Adjusted cash flows from operations	$	15,657		$	12,815		$	66,199		$	50,557

_________________________________

⁽¹⁾  The year ended December 31, 2014 includes the benefit of an $8.6 million non-recurring adjustment related to an arbitration settlement.

16

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

	For the Three Months Ended December 31,						For the Years Ended December 31,
	2014			2013			2014			2013
	(in thousands, except share and per share data)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED (1)	$	26,671		$	(3,344	)	$	36,529		$	39,964
Interest expense	6,777			5,575			27,571			13,168
Depreciation, depletion and amortization	12,407			11,021			46,180			32,449
Income tax benefit	—			(16,042		)	—			(16,042		)
EBITDA	45,855			(2,790		)	110,280			69,539
Dividend expense	3,619			2,980			14,424			9,378
Accretion of asset retirement obligation	130			110			506			468
Loss (gain) on acquisition of assets at fair value	—			16,042			—			(27,670		)
(Gains) losses related to the change in mark to market value for outstanding commodity derivatives contracts	(24,852		)	2,811			(23,902		)	9,967
Non-cash stock compensation expense	1,186			895			4,890			3,435
Litigation settlement expense	—			—			—			1,000
Foreign transaction (gain) loss	—			(1		)	7			14
Investment income and other	(4		)	(32		)	(19		)	(48		)
Non-recurring general and administrative costs related to acquisition of assets	—			639			30			2,349
Non-recurring general and administrative costs related to Parent migration	—			593			233			1,183
Non-recurring severance costs related to property divestment	—			—			—			659
Adjusted EBITDA	$	25,934		$	21,247		$	106,449		$	70,274

_________________________________

⁽¹⁾  The year ended December 31, 2014 includes the benefit of an $8.6 million non-recurring adjustment related to an arbitration settlement.

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